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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

____________________________________

FORM 10-K


☒			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

THE AES CORPORATION

(Exact name of registrant as specified in its charter)


Delaware						54-1163725
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


4300 Wilson Boulevard
Arlington,	Virginia	22203
(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			124
Note 1 - General and Summary of Significant Accounting Policies			126
Note 2 - Inventory			139
Note 3 - Property, Plant, and Equipment			139
Note 4 - Asset Retirement Obligations			140
Note 5 - Fair Value			140
Note 6 - Derivative Instruments and Hedging Activities			146
Note 7 - Financing Receivables			147
Note 8 - Allowance for Credit Losses			148
Note 9 - Investments in and Advances to Affiliates			149

Note 10 - Goodwill and Other Intangible Assets			150
Note 11 - Regulatory Assets and Liabilities			152
Note 12 - Obligations			153
Note 13 - Commitments			159
Note 14 - Contingencies			159
Note 15 - Leases			161
Note 16 - Benefit Plans			163
Note 17 - Redeemable Stock of Subsidiaries			166
Note 18 - Equity			169
Note 19 - Segments and Geographic Information			174
Note 20 - Share-Based Compensation			179
Note 21 - Revenue			181
Note 22 - Other Income and Expense			182
Note 23 - Asset Impairment Expense			184
Note 24 - Income Taxes			186

Note 25 - Held-for-Sale and Dispositions			191
Note 26 - Acquisitions			193
Note 27 - Earnings Per Share			195
Note 28 - Risks and Uncertainties			197
Note 29 - Related Party Transactions			198


N ote 30 - Restructu ring			199
Note 3 1 - Discontinued Operations			199
Note 3 2 - Subsequent Events			200
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			201
ITEM 9A. CONTROLS AND PROCEDURES			201
ITEM 9B. OTHER INFORMATION			204
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS			204
PART III			205
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			205
ITEM 11. EXECUTIVE COMPENSATION			205
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			205
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			205
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES			206
PART IV - ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE			207
SIGNATURES			210


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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 EBITDA with Tax Attributes			Adjusted earnings before interest income and expense, taxes, depreciation, amortization, and accretion of AROs, 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
AES Ohio			The Dayton Power & Light Company, formerly branded as DP&L. For the periods covered by this report, AES Ohio 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			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


CO2			Carbon 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			DPL LLC and its consolidated subsidiaries. On April 3, 2025, DPL Inc. converted its form of business organization from 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


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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
NOX			Nitrogen 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

SO2			Sulfur 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


3 \| 2025 Annual Report

PART I

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;


4 \| 2025 Annual Report

•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.


5 \| 2025 Annual Report

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


6 \| 2025 Annual Report

customers.

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

2025 Strategic Highlights

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

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

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

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

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

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

Overview

Generation

We currently own and/or operate a generation portfolio of 34,740 MW, including generation from our integrated utility, AES Indiana. Our generation fleet is diversified by technologies and fuel type. See discussion below under Fuel Costs.

Performance drivers of our generation businesses include types of electricity sales agreements, plant reliability and flexibility, availability of generation capacity to meet contracted sales, fuel costs, seasonality, weather variations, economic activity, fixed-cost management, and competition. The financial performance of our renewables business is also impacted by our ability to complete construction projects and earn U.S. renewable tax credits.

Contract Sales — Most of our generation businesses sell electricity and associated generation attributes under medium- or long-term contracts ("PPAs") in either regulated or competitive markets ("contract sales") or under short-term agreements in competitive markets ("short-term sales"). Our medium-term contract sales have terms of two to five years, while our long-term contracts have terms of more than five years. These contract sales and short-term sales may also include RECs, as discussed below.

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

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

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

Many of these contracts are intended to reduce exposure to the volatility of fuel and electricity prices by linking the business's revenues and costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the currency of revenue and expenses, including fixed costs and debt. Our project debt may


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consist of both fixed and floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the Short-Term Sales section below.

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

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

Many of the short-term markets in which we operate include regulated capacity markets. These capacity markets are intended to provide additional revenue based upon availability without reliance on the energy margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand). Our generating facilities selling in the short-term markets typically receive capacity payments based on their availability in the market.

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

Plant Reliability and Flexibility — Our contract and short-term sales provide incentives to our generation plants to optimally manage availability, operating efficiency, and flexibility. Capacity payments under contract sales are frequently tied to meeting minimum standards. In short-term sales and certain contract sales, our plants must be reliable and flexible to capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture ancillary service revenue while meeting local market needs.

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

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

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

29% of the capacity of our generation plants is fueled by natural gas. With the exception of our plants in the Dominican Republic and Panama, where we import LNG to utilize in the local market, we use gas from local suppliers in each market.

15% of the capacity of our generation fleet is coal-fired. In the U.S., most of our coal-fired plants are supplied from domestic coal. At our non-U.S. generation plants, and at our plant in Puerto Rico, we source coal from a mix of sources from the international market and in the local jurisdictions. To the extent possible, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.


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

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

Fixed-Cost Management — In our businesses with long-term contracts, the majority of the fixed O&M costs are recovered through the capacity payment or were otherwise factored in as a component of the long-term contract price. However, for all generation businesses, managing fixed costs and reducing them over time is a driver of business performance.

Competition — For our businesses with medium- or long-term contracts, there is limited market competition impacting prices during the term of the contract. For short-term sales, plant dispatch and the price of electricity are determined by market competition and local dispatch and reliability rules.

Utilities

Our utility businesses consist of AES Indiana and AES Ohio in the U.S., and four utilities in El Salvador. AES' six utility businesses distribute power to 2.7 million customers and AES' two utilities in the U.S. also include generation capacity totaling 4,056 MW.

AES Indiana, our fully integrated regulated utility, and AES Ohio, our transmission and distribution regulated utility, each operate as the sole distributors of electricity within their respective jurisdictions. AES Indiana owns and operates all of the facilities necessary to generate, transmit, and distribute electricity. AES Ohio owns and operates all of the facilities necessary to transmit and distribute electricity. Our distribution businesses in El Salvador face limited competition due to significant barriers to enter the market. According to El Salvador's regulation, large regulated customers have the option of becoming unregulated users and requesting service directly from generation or commercialization agents.

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

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

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

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

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


9 \| 2025 Annual Report

therefore, need to manage costs to the levels reflected in the tariff, or risk non-recovery of costs or diminished returns.

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

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

Development and Construction

We develop and construct new generation facilities. For our utility businesses, new plants may be built or existing plants retrofitted in response to customer needs or to comply with regulatory developments. The projects are developed subject to regulatory approval that permits recovery of our capital cost and a return on our investment. For our generation businesses, our priority for development is in key growth markets, such as the U.S. and Chile, where we can leverage our global scale and synergies with our existing businesses by adding renewable energy. We make the decision to invest in new projects by evaluating the strategic fit, financial profile, projected returns, and risk for the investment and against alternative uses of capital, including corporate debt repayment. For some development projects, rather than advancing them through construction and maintaining long-term ownership of an operating facility, AES may monetize project value by entering into Develop-Transfer Agreements ("DTAs") in which we transfer assets to a third party prior to construction in exchange for appropriate compensation. AES also provides development services, where we enter into contracts to fully develop customized assets to meet customers' needs. These DTAs and development service contracts may be entered into for new generation facilities or other potential uses of our development assets, including for data centers.

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

Segments

The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the businesses internally and is mainly organized by technology.

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

We have two lines of business: generation and utilities. Our Renewables, Utilities, and Energy Infrastructure SBUs participate in our first business line, generation, in which we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. Our Utilities SBU participates in our second business line, utilities, in which we own and/or operate utilities to generate or purchase, transmit, distribute, and sell electricity to end-user customers in the residential, commercial, industrial, and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market. Our New Energy Technologies SBU includes investments in new and innovative technologies to support leading-edge greener energy solutions.

We measure the operating performance of our SBUs using Adjusted EBITDA, a non-GAAP measure. The Adjusted EBITDA by SBU for the year ended December 31, 2025 is shown below. The percentages for Adjusted EBITDA are the contribution by each SBU to the gross metric, i.e., the total Adjusted EBITDA by SBU, before deductions for Corporate. Our New Energy Technologies SBU generated losses for the year ended December 31,


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2025. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted EBITDA.

For financial reporting purposes, the Company's corporate activities are reported within "Corporate and Other" because they do not require separate disclosure. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 19—Segment and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further discussion of the Company's segment structure.


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a2025formsbuinfographics001 RNW Feb 26.jpg



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


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Renewables

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

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

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


Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
OpCo A (1)	US-Various	Solar	967	26	%	2017-2019	2028-2046	Various
		Wind	140
Alicura (2)	Argentina	Hydro	1,050	100	%	2000
Chivor	Colombia	Hydro	1,000	99	%	2000	2026-2039	Various
Bellefield 1	US-CA	Solar	500	75	%	2025	2040	Amazon
		Energy Storage	500
New York Wind (OpCo D) (3)	US-NY	Wind	612	75	%	2021		NYISO
Rexford (OpCo E) (3)	US-CA	Solar	300	100	%	2024	2039	Clean Power Alliance of Southern California
		Energy Storage	240
Alto Maipo	Chile	Hydro	531	99	%	2021	2040	Minera Los Pelambres
OpCo E (3)	US-Various	Solar	420	100	%	2015-2025	2029-2045	Various
		Energy Storage	78
Spotsylvania Solar Energy Center (1) (3)	US-VA	Solar	485	50	%	2020-2021	2035	Apple, Akamai, Etsy, Microsoft
Chevelon Butte (OpCo D) (3)	US-AZ	Wind	454	75	%	2023-2024	2043-2044	APS
McFarland B (OpCo D) (3)	US-AZ	Solar	300	75	%	2023-2024	2043	Amazon
		Energy Storage	150
West Camp (OpCo D) (3)	US-AZ	Wind	420	75	%	2025	2045	APS
Andes Solar 3	Chile	Solar	171	100	%	2025	2040	Codelco
		Energy Storage	171
Andes Solar 4	Chile	Solar	211	51	%	2023-2024	2026-2042	Google, Various
		Energy Storage	130
Andes 2b	Chile	Solar	207	51	%	2023-2024		Various
		Energy Storage	129
Mesa La Paz (1)	Mexico	Wind	306	50	%	2019	2045	Fuentes de Energia Peñoles
McFarland A (OpCo D) (3)	US-AZ	Solar	200	75	%	2023	2038	BP
		Energy Storage	100
OpCo B (1)	US-Various	Solar	297	26	%	2019	2039-2044	Various
Bolero	Chile	Solar	146	51	%	2023-2025	2038-2042	Various
		Energy Storage	146	89	%
Bayano	Panama	Hydro	260	49	%	1999	2030	ENSA, Edemet, Edechi, Other
Morris (OpCo D) (3)	US-MO	Solar	250	75	%	2025	2040	Microsoft
Cordillera Hydro Complex (4)	Chile	Hydro	240	99	%	2000	2042	Various
Baldy Mesa (OpCo D) (3)	US-CA	Solar	150	75	%	2023	2043	Amazon
		Energy Storage	75
Changuinola	Panama	Hydro	223	90	%	2011	2030	AES Panama


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Great Cove 1&2 (OpCo D) (3)	US-PA	Solar	220	75	%	2023	2043	University of Pennsylvania
Raceway 1 (1)	US-CA	Solar	125	50	%	2023	2043	Microsoft
		Energy Storage	80
Prevailing Winds (OpCo B) (1)	US-SD	Wind	200	26	%	2020	2050	Basin Electric Power Cooperative
Oak Ridge (OpCo D) (3)	US-LA	Solar	200	75	%	2023	2043	Amazon
OpCo D	US-Various	Solar	177	75	%	2022-2025	2042-2045	Various
		Energy Storage	22
Delta (OpCo D) (3)	US-MS	Wind	185	75	%	2023-2024	2043-2044	Amazon
McFarland C (OpCo D) (3)	US-CA	Energy Storage	185	75	%	2025	2045	Southern California Edison
Skipjack (OpCo D) (3)	US-VA	Solar	175	75	%	2022	2036	Constellation Energy Generation
Andes Solar 2a	Chile	Solar	81	51	%	2021-2024	2038	Google, Various
		Energy Storage	80
St. Nikola	Bulgaria	Wind	156	89	%	2010	2026	KER Toki
Cavalier (OpCo D) (3)	US-VA	Solar	156	75	%	2023-2024	2043	Dominion Energy
Atacama Solar	Chile	Solar	150	99	%	2024	2035	Collahuasi
Peravia I&II (1)	Dominican Republic	Solar	140	33	%	2025	2036-2040	Andres, Ede Sur
Lancaster Area Battery (LAB) (OpCo D) (3)	US-CA	Energy Storage	127	75	%	2022	2037	PG&E
Calhoun (OpCo D) (3)	US-MI	Solar	125	75	%	2024	2039	Microsoft, MPPA
Chiriqui-Esti	Panama	Hydro	120	49	%	2003	2030	ENSA, Edemet, Edechi, Other
Kuihelani (OpCo E) (3)	US-HI	Solar	60	100	%	2023-2024	2048	HECO
		Energy Storage	60
Los Olmos	Chile	Wind	110	51	%	2022	2032	Google, Various
Los Cururos	Chile	Wind	109	51	%	2019		Various
Cabra Corral	Argentina	Hydro	102	100	%	1995		Various
Southland Energy—Alamitos Energy Center	US-CA	Energy Storage	100	50	%	2021	2041	Southern California Edison
East Line Solar (OpCo B) (1)	US-AZ	Solar	100	26	%	2020	2045	Salt River Project Agricultural Improvement & Power District
Central Line (OpCo B) (1)	US-AZ	Solar	100	26	%	2022	2039	Salt River Project Agricultural Improvement & Power District
West Line (1)	US-AZ	Solar	100	50	%	2022	2047	Salt River Project Agricultural Improvement & Power District
Luna (OpCo D) (3)	US-CA	Energy Storage	100	75	%	2022	2037	Clean Power Alliance of Southern California
Vientos Bonaerenses	Argentina	Wind	100	100	%	2020	2026-2040	Various
Vientos Neuquinos	Argentina	Wind	100	100	%	2020	2026-2040	Various
Mirasol (1)	Dominican Republic	Solar	100	33	%	2024	2039	Ede Este
Laurel Mountain Repowering (OpCo D) (3)	US-WV	Wind	99	75	%	2022	2037	AES CE Solutions, LLC
Estrella (1)	US-CA	Solar	56	50	%	2023	2038	Clean Power Alliance of Southern California
		Energy Storage	28
Cavalier Solar A2 (OpCo D) (3)	US-VA	Solar	84	75	%	2024	2044	Microsoft
Alamitos 2 (OpCo E) (3)	US-CA	Energy Storage	82	100	%	2024	2044	Southern California Edison
San Matias	Chile	Wind	82	51	%	2023-2025	2038	Microsoft
Platteview (OpCo D) (3)	US-NE	Solar	81	75	%	2023	2043	Omaha Public Power District
Clover Creek (OpCo B) (1)	US-UT	Solar	80	26	%	2021	2046	UMPA


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Westwing 1 (OpCo E) (3)	US-AZ	Energy Storage	80	100	%	2023-2024	2043-2044	APS
Silver Peak (OpCo D) (3)	US-CA	Solar	50	75	%	2024	2044	Amazon
		Energy Storage	25
Mesamávida	Chile	Wind	68	51	%	2022-2023	2038	Google, Various
Mountain View Repowering (OpCo D) (3)	US-CA	Wind	67	75	%	2022	2042	Central Coast Community Energy, Silicon Valley Clean Energy Authority
Campo Lindo	Chile	Wind	66	51	%	2023		Various
Madison (OpCo D) (3)	US-VA	Solar	63	75	%	2024	2039	Northrop Grumman
Westwing 2A (OpCo D) (3)	US-AZ	Energy Storage	62	75	%	2024	2044	APS
San Fernando	Colombia	Solar	61	99	%	2021	2036	Ecopetrol
Big Island Waikoloa (OpCo E) (3)	US-HI	Solar	30	100	%	2022-2023	2047	HECO
		Energy Storage	30
Waiawa Phase 2	US-HI	Solar	30	75	%	2025	2045	HECO
		Energy Storage	30
Westwing 2B (OpCo D) (3)	US-AZ	Energy Storage	59	75	%	2024	2044	APS
Keydet North	US-VA	Solar	58	75	%	2025	2045	Microsoft
Penonome I	Panama	Wind	55	49	%	2020	2030	ENSA, Edemet, Edechi
Chiriqui-Los Valles	Panama	Hydro	54	49	%	1999	2030	ENSA, Edemet, Edechi, Other
Bayasol (1)	Dominican Republic	Solar	50	33	%	2021	2036	Ede Sur
Agua Clara (1)	Dominican Republic	Wind	50	33	%	2022	2039	Ede Norte
Santanasol (1)	Dominican Republic	Solar	50	33	%	2022	2038	Ede Sur
Virtual Reservoir 2	Chile	Energy Storage	50	99	%	2023
Mountain View IV (OpCo E) (3)	US-CA	Wind	49	100	%	2012	2032	Southern California Edison
Chiriqui-La Estrella	Panama	Hydro	48	49	%	1999	2030	ENSA, Edemet, Edechi, Other
AM Solar	Jordan	Solar	48	36	%	2019	2039	National Electric Power Company
Ullum	Argentina	Hydro	45	100	%	1996		Various
Lawa'i (3)	US-HI	Solar	20	100	%	2018	2043	Kaua'i Island Utility Cooperative
		Energy Storage	20
Kekaha (3)	US-HI	Solar	14	100	%	2019	2045	Kaua'i Island Utility Cooperative
		Energy Storage	14
Brisas	Colombia	Solar	27	99	%	2022	2037	Ecopetrol
West Oahu Solar (OpCo E) (3)	US-HI	Solar	12.5	100	%	2023	2048	HECO
		Energy Storage	12.5
Na Pua Makani (OpCo E) (3)	US-HI	Wind	24	100	%	2020	2040	HECO
Ilumina	US-PR	Solar	24	100	%	2012	2037	PREPA
Andes Solar 1	Chile	Solar	22	99	%	2016	2036	Quebrada Blanca
Castilla	Colombia	Solar	21	99	%	2019	2034	Ecopetrol
Tunjita	Colombia	Hydro	20	99	%	2016	2026-2039	Various
Cochrane ES (5)	Chile	Energy Storage	20	97	%	2016
Angamos ES	Chile	Energy Storage	20	99	%	2011
Esti Solar II	Panama	Solar	18	49	%	2025	2030	ENSA, Edemet, Edechi, Other
Laurel Mountain ES (OpCo E) (3)	US-WV	Energy Storage	16	100	%	2011


15 \| 2025 Annual Report


Community Energy	US-Various	Solar	14	75	%	2022	2030-2039	Various
Andes (6)	Chile	Energy Storage	12	99	%	2009
Southland Energy—AES Gilbert (Salt River) (7)	US-AZ	Energy Storage	10	50	%	2019	2039	Salt River Project Agricultural Improvement & Power District
El Tunal	Argentina	Hydro	10	100	%	1995		Various
Andres ES	Dominican Republic	Energy Storage	10	65	%	2017
Los Mina DPP ES	Dominican Republic	Energy Storage	10	65	%	2017
Pesé Solar	Panama	Solar	10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Mayorca Solar	Panama	Solar	10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Cedro	Panama	Solar	10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Caoba	Panama	Solar	10	49	%	2021	2030	ENSA, Edemet, Edechi, Other
Netherlands ES	Netherlands	Energy Storage	10	100	%	2015
Alfalfal Virtual Reservoir	Chile	Energy Storage	10	99	%	2020
Corotú	Panama	Solar	10	49	%	2025	2030	ENSA, Edemet, Edechi, Other
Los Santos	Panama	Solar	8	49	%	2025	2030	ENSA, Edemet, Edechi, Other
OpCo C (1)	US-Various	Solar	6	50	%	2021-2022	2041-2042	Various
Warrior Run ES	US-MD	Energy Storage	5	100	%	2016
5B Colon	Panama	Solar	1	100	%	2021	2051	Costa Norte LNG Terminal
PFV Kaufmann	Chile	Solar	1	99	%	2021	2040	Kaufmann
			17,836

_____________________________

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

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

(3)AES owns these assets together with third-party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, which vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as Noncontrolling interest or Redeemable stock of subsidiaries on the Consolidated Balance Sheets, depending on the partnership rights of the specific project.

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

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

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

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


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


Business	Location	Fuel	Gross MW	AES Equity Interest		Expected Date of Commercial Operations
Keydet	US-VA	Solar	62	75	%	1H 2026
West Camp	US-AZ	Wind	80	75	%	1H 2026
Halifax	US-NC	Solar	80	75	%	1H 2026
Jobos	US-PR	Solar	80	70	%	1H 2026
		Energy Storage	110
Salinas	US-PR	Solar	120	70	%	1H 2026
		Energy Storage	175
Arenales	Chile	Energy Storage	300	100	%	1H 2026
Armadillo	US-TX	Solar	200	75	%	1H 2026
AES Clean Energy Development	US-Various	Solar	12	75	%	1H-2H 2026
Bellefield 2	US-CA	Solar	500	75	%	2H 2026
		Energy Storage	500
Windsor	US-VA	Solar	85	75	%	2H 2026
Baldy Mesa Energy Storage	US-CA	Energy Storage	50	75	%	1H 2027
Vientos Bonaerenses 3 and 4	Argentina	Wind	102	100	%	1H 2027
Buffalo Gap Repowering	US-TX	Wind	527	100	%	1H 2027
Cristales	Chile	Solar	287	100	%	1H 2027
		Energy Storage	340
Pampas	Chile	Solar	229	100	%	1H 2027
		Energy Storage	340
		Wind	128
Atacama	Chile	Energy Storage	250	100	%	1H 2027
Four Horizons	US-TX	Wind	945	75	%	2H 2027 - 1H 2028
			5,502

AES Clean Energy

Business Description — AES' U.S. renewables portfolio, referred to as AES Clean Energy, is the leading U.S. renewables growth platform in serving large corporations with its 46 GW development pipeline. AES Clean Energy aims to solve customers' energy challenges by offering an expanded portfolio of innovative solutions based on cutting-edge technologies that are designed to accelerate customers' time to power, while delivering green attributes. The generation capacity of the systems owned and/or operated under AES Clean Energy is 10,961 MW across the U.S., with another 3,031 MW under construction, including 1,542 MW of wind, 939 MW of solar, and 550 MW of energy storage. AES Clean Energy has a 7.6 GW backlog of projects, the majority of which are expected to come online through 2029. The expansion of data center needs related to the growing use of generative artificial intelligence are expected to be a significant accelerant to the growth of the U.S. renewables market and AES seeks to capture a significant portion of this market expansion.

AES Clean Energy comprises AES Renewable Holdings, sPower, AES Clean Energy Development, and other renewables assets as part of its broader investments in the U.S. AES Clean Energy Development serves as the development vehicle for all future renewables projects in the U.S. AES Clean Energy Development is a leader in the U.S. renewables industry, and, in 2025, it added over 2.1 GW of high-quality projects to its backlog.

Key Financial Drivers — The financial results of AES Clean Energy are primarily driven by the efficient construction and operation of renewable energy facilities across the U.S. under long-term PPAs (including long-term REC contracts), through which the energy price on the entire production of these facilities is determined. Tax credits associated with the development of U.S. renewables projects can be substantial and have increased with the adoption of the Inflation Reduction Act ("IRA"). In 2025, AES recognized $1.5 billion related to the monetization of tax attributes to tax equity investors and transferability tax credit buyers relating to U.S. renewables projects, $166 million of which relates to solar projects owned by our utility at AES Indiana. The financial results of U.S. renewables assets are primarily driven by the amount of wind or solar resource at the facilities, availability of facilities, growth in projects, the profitable development and sale of energy, RECs, and other generation attributes to customers, and by tax credit recognition once placed in service.


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

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

Development Strategy — As states, communities, and organizations of all types make commitments and plan to reduce their carbon footprints, renewables are the fastest-growing source of electricity generation in the U.S. AES Clean Energy works with its customers to co-create and deliver the smarter, greener energy solutions that meet their needs. For corporate customers, this includes advanced 24/7 carbon‑free energy offerings tailored to support large energy‑intensive operations, such as hyperscale data centers, by combining renewables, storage, and load‑siting solutions. Concurrently, AES develops and delivers ready‑to‑build renewable energy projects and powered land for regulated utilities and corporate customers through Develop-Transfer Agreements, in which AES manages the full greenfield development process (including permitting, engineering, and procurement) and transfers the project once it reaches construction‑ready status. AES has worked with several major technology companies to provide clean energy solutions to power their networks of data centers, and we expect these relationships to expand as the rapid adoption of generative artificial intelligence drives significant growth in data center electricity demand.

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

AES Chile

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

AES Andes' Green Blend strategy aims to reduce carbon intensity and to incorporate renewable energy to extend our previous conventional PPAs by de-linking our PPAs from legacy fossil resources while growing our renewable energy portfolio. This strategy delivers a competitive and reliable energy solution for customers, AES Chile has committed to advance the development of new renewables projects, including the implementation of BESS and other technological innovations that will provide greater flexibility and reliability to the system.

AES Andes currently has long-term contracts with an average remaining term of approximately 14 years with unregulated customers, such as mining and industrial companies, mainly with pricing indexed to CPI.

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

•spot market prices (largely impacted by dry hydrological scenarios, forced outages, and international fuel prices);

•changes in current regulatory rulings, tax policies; and

•fluctuations of the Chilean peso.

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


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different stages and geographical locations.

AES Argentina

Business Description — In Argentina, AES owns and operates two fully contracted wind power plants totaling 200 MW and operates 157 MW of hydroelectric power plants. In addition, AES Argentina previously operated the 1,050 MW Alicura hydroelectric plant under a concession contract which ended on January 9, 2026. The total 1,407 MW represents 3% of the country's total installed capacity. AES Argentina's plants are placed in strategic locations within the country in order to provide energy to the spot market and customers.

AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2025, approximately 70% of the energy sold was produced by the hydroelectric power plants and sold in the wholesale electricity market and the remaining 30% was generated by the wind power plants.

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

•forced outages;

•exposure to fluctuations of the Argentine peso;

•changes in hydrology and wind resources; and

•domestic energy demand and exports.

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

AES Colombia

Business Description — We operate in Colombia through AES Colombia, a subsidiary of AES Andes, which owns Chivor, a hydroelectric plant with an installed capacity of 1,000 MW and Tunjita, a 20 MW run-of-river hydroelectric plant, both located approximately 100 miles east of Bogota, as well as the Castilla, Brisas, and San Fernando solar facilities with capacity of 21 MW, 26 MW, and 61 MW, respectively. AES Colombia’s installed capacity accounted for approximately 5% of system capacity at the end of 2025. AES Colombia is dependent on hydrological conditions, which influence generation and spot prices of non-contracted generation in Colombia.

AES Colombia's commercial strategy aims to execute contracts with commercial and industrial customers and bid in public tenders, mainly with distribution companies, in order to reduce margin volatility with proper portfolio risk management. The remaining energy generated by our portfolio is sold to the spot market, including ancillary services. Additionally, AES Colombia receives reliability payments for maintaining the plant's availability and generating firm energy during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.

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

•forced outages;

•fluctuations of the Colombian peso; and

•spot market prices.

Development Strategy — AES Colombia is committed to supporting its customers to diversify their energy supply and become more competitive. As part of this commitment, AES Colombia is developing a pipeline of 1.3 GW of solar and wind projects. Six wind projects totaling 1,149 MW are located in La Guajira, one of the windiest spots in the world, and in 2025, all relevant permits for 259 MW were obtained. In 2025, AES Colombia executed an investment agreement for a partnership structure with Ecopetrol S.A. in connection with these projects. Under the terms of the partnership, the projects will be contributed to two trusts, which will own, construct, operate, and maintain the projects and sell the energy generated to Ecopetrol under a PPA.

AES Panama

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


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The majority of our hydroelectric plants in Panama are based on run-of-the-river technology, with the exception of 223 MW Changuinola plant with regulating reservoirs and the 260 MW Bayano plant. Hydrological conditions have an important influence on profitability. Variations in hydrology can result in an excess or a shortfall in energy production relative to our contractual obligations. Hydro generation is generally in a shortfall position during the dry season from January through May, which is offset by thermal and wind generation since its behavior is opposite and complementary to hydro generation.

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

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

•changes in hydrology, which impacts spot prices and exposes the business to variability in the cost of replacement power;

•fluctuations in commodity prices, mainly fuel oil and natural gas, which affect the cost of thermal generation and spot prices;

•constraints imposed by the capacity of transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the rainy season; and

•country demand as GDP growth is expected to remain stable over the short and medium term.

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

AES Puerto Rico

Business Description — AES Puerto Rico owns and operates Ilumina, a 24 MW solar facility in Puerto Rico. The plant is fully contracted through a long-term PPA with PREPA expiring in 2037. In addition, in 2024, AES began construction on 485 MW of new renewables projects. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPAs with PREPA.

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

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

AES Dominicana

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

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

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

•change in wind and solar resources due to heavy rains, hurricanes, and other natural events that may affect the country;

•constraints imposed by the capacity of transmission lines and potential delays on the transmission expansion projects; and

•related to projects under construction, changes in execution cost and scope of work that may delay the operation of the new renewables plants.

AES Mexico

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


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2045.

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

•contracting levels, providing additional benefits from improved operational performance, including performance incentives and/or excess energy sales;

•changes in the methodology to calculate spot energy prices or Locational Marginal Prices, which impacts the excess energy sales;

•improved operational performance and plant availability; and

•changes in wind resources.

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

AES Bulgaria

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

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

•regulatory changes in the Bulgarian power market;

•availability and load factor of the operating units;

•the level of wind resources; and

•spot market price volatility.

In December 2022, Bulgaria implemented Regulation 2022/1854, approved by the European Council in October 2022 as an emergency intervention aiming at limiting energy prices in Europe. The main measure of interest to AES in Bulgaria is the limitation of revenues for "infra-marginal" producers, a category that includes renewables and other technologies which are providing electricity to the grid at a cost below the price level set by the more expensive “marginal” producers.

AES Jordan

Business Description — In Jordan, AES has a 36% controlling interest in a 48 MW solar plant fully contracted with the national utility under a 20-year PPA expiring in 2039. We consolidate the results of this business as we have a controlling interest.


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a2025formsbuinfographics001 UTIL Feb 26.jpg



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


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Utilities

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

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

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


Business	Location	Type	AES Equity Interest		Approximate Number of Customers Served as of 12/31/2025	Approximate GWh Sold in 2025	Fuel	Gross MW	Year Acquired or Began Operation
CAESS	El Salvador	Distribution	75	%	683,000	2,370			2000
CLESA	El Salvador	Distribution	80	%	506,000	1,307			1998
DEUSEM	El Salvador	Distribution	74	%	101,000	197			2000
EEO	El Salvador	Distribution	89	%	377,000	870			2000
El Salvador Subtotal					1,667,000	4,744
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.


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

_____________________________

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


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

Business

Location

Fuel

Gross MW

AES Equity Interest

Expected Date of Commercial Operations

Santa Ana IV

El Salvador

Solar

100

1H 2026

Crossvine (AES Indiana)

US-IN

Solar

1H 2027

Energy Storage

225

AES Indiana

Business Description — IPALCO is a holding company whose principal subsidiary is AES Indiana. AES Indiana is an integrated utility that is engaged primarily in generating, transmitting, distributing, and selling electric energy to retail customers in the city of Indianapolis and neighboring areas within the state of Indiana and is subject to regulatory authority—see Regulatory Framework and Market Structure below. AES Indiana has an exclusive right to provide electric service to the customers in its service area, covering about 528 square miles with an estimated population of approximately 982,000 people.

AES Indiana owns and operates four generating stations, all within the state of Indiana. The first station, Petersburg, consists of two coal-fired units; however, AES Indiana is in the process of converting these remaining two coal-fired units to natural gas in 2026 (see Integrated Resource Plan below). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. AES Indiana also operates a 20 MW battery-based energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. In addition, AES Indiana helps meet its customers' energy needs with long-term contracts for the purchase of 200 MW of wind-generated electricity and 94 MW of solar-generated electricity.

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

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

Key Financial Drivers — AES Indiana's financial results are driven primarily by retail demand, weather, and maintenance costs. In addition, AES Indiana's financial results are likely to be driven by many other factors including, but not limited to:

•regulatory outcomes and impacts;

•the passage of new legislation, implementation of regulations, or other changes in regulation; and

•timely recovery of capital expenditures and operation and maintenance costs.

Regulatory Framework and Market Structure — AES Indiana is subject to comprehensive regulation by the IURC with respect to its services and facilities, retail rates and charges, the issuance of long-term securities, and certain other matters. The regulatory authority of the IURC over AES Indiana's business is typical of regulation generally imposed by state public utility commissions. The IURC sets tariff rates for electric service provided by AES Indiana. The IURC considers all allowable costs for ratemaking purposes, including a fair return on assets used and useful to providing service to customers.

AES Indiana's tariff rates for electric service to retail customers consist of basic rates and approved charges. In addition, AES Indiana's rates include various adjustment mechanisms, including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet AES Indiana's retail load requirements, referred to as the Fuel Adjustment Charge, (ii) a rider for the timely recovery of costs (including a return) to comply with environmental laws and regulations and investments in renewable energy projects, and recovery of costs related to generation consumables and environmental allowance expenses, referred to as the ECCRA, (iii) a rider to reflect changes in ongoing RTO costs, (iv) riders for passing through to customers wholesale sales margins and capacity sales above and below established annual benchmarks, (v) a rider for the timely recovery of costs (including a return) incurred for eligible TDSIC improvements, and (vi) a rider for cost recovery, lost margin recoveries, and performance incentives from AES Indiana's demand side management energy efficiency programs. Each of these tariff rate


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components function somewhat independently of one another, but the overall structure of AES Indiana's rates is subject to review at the time of any review of AES Indiana's basic rates and charges. Additionally, AES Indiana's rider recoveries are reviewed through recurring filings.

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

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

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

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

Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first 80% of eligible costs can be recovered using a periodic rate adjustment mechanism, referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation, and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in the public utility’s next base rate case. The TDSIC mechanism is capped at an annual increase of two percent of total retail revenues.

On March 4, 2020, the IURC issued an order approving the projects in AES Indiana's seven-year TDSIC Plan for eligible transmission, distribution, and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on, and of, investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered with the TDSIC rider rate filings by six months as ordered by the IURC and are filed each December.

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


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

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

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

AES Indiana expects to spend an estimated $4.2 billion on capital projects from 2026 through 2028. This total includes spending on AES Indiana's power generation and renewable energy projects discussed above, spending under AES Indiana's TDSIC Plan, as well as other new transmission and distribution projects. The estimated spending includes projects that are subject to regulatory approval, as well as estimated spending under AES Indiana's 2025 IRP.

AES Ohio

Business Description — DPL is a holding company whose principal indirect subsidiary is AES Ohio. AES Ohio is a utility company that transmits and distributes electricity to approximately 541,000 retail customers in a 6,000 square mile area of West Central Ohio and is subject to regulatory authority—see Regulatory Framework and Market Structure below. AES Ohio has the exclusive right to provide transmission and distribution services to its customers, and procures retail standard service offer ("SSO") electric service on behalf of residential, commercial, industrial, and governmental customers through a competitive bid auction process.

Key Financial Drivers — AES Ohio's financial results are driven primarily by retail demand and weather. AES Ohio's financial results are likely to be driven by other factors as well, including, but not limited to:

•regulatory outcomes and impacts;

•the passage of new legislation, implementation of regulations, or other changes in regulations; and

•timely recovery of transmission and distribution expenditures.

Regulatory Framework and Market Structure — AES Ohio is regulated by the PUCO for its distribution services and facilities, retail rates and charges, reliability of service, compliance with renewable energy portfolio requirements, energy efficiency program requirements, and certain other matters. The PUCO maintains jurisdiction over the delivery of electricity, SSO, and other retail electric services.

Electric customers within Ohio are permitted to purchase power under contract from a Competitive Retail Electric Service ("CRES") provider or from their local utility under SSO rates. The SSO generation supply is provided by third parties through a competitive bid process. Ohio utilities have the exclusive right to provide transmission and distribution services in their state-certified territories. While Ohio allows customers to choose retail generation providers, AES Ohio is required to provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider or as a provider of last resort in the event of a CRES provider default. SSO rates are subject to rules and regulations of the PUCO and are established through a competitive bid process for the supply of power to SSO customers.

AES Ohio's distribution rates are regulated by the PUCO and are established through a traditional cost-based rate-setting process. AES Ohio is permitted to recover its costs of providing distribution service as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure, and cost of capital. AES Ohio's retail rates include various adjustment mechanisms including, but not limited to, the timely recovery of costs incurred related to power purchased through the competitive bid process, participation in the PJM RTO, severe storm damage, and energy efficiency.

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

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

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


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

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

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

ESP 4 — On September 26, 2022, AES Ohio filed its latest ESP ("ESP 4") with the PUCO. ESP 4 is a comprehensive plan to enhance and upgrade its network and improve service reliability, provide safeguards for price stability, and continue investments in local economic development. In April 2023, AES Ohio entered into a Stipulation and Recommendation with the PUCO Staff and seventeen parties (the "ESP 4 Settlement") with respect to AES Ohio’s ESP 4 application, and, in August 2023, the PUCO issued their opinion and order accepting the ESP 4 Settlement as filed. AES Ohio is currently operating under this ESP 4 until its expiration, which was extended to May 31, 2027 based on House Bill 15, unless superseded by a Commission-approved Three-Year Rate Plan and MRO.

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

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


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

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

Development Strategy — Planned construction projects primarily relate to new investments in and upgrades to AES Ohio's transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments, and changing environmental standards, among other factors.

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

AES El Salvador

Business Description — AES El Salvador is the majority owner of four of the five distribution companies operating in El Salvador (CAESS, CLESA, EEO, and DEUSEM). AES El Salvador's territory covers 77% of the country and accounted for 4,744 GWh of the market energy sales during 2025. AES El Salvador owns and operates four solar farms: Opico Power, Moncagua, and Metapan with 4 MW, 3 MW, and 15 MW of capacity, respectively, and Meanguera del Golfo, a solar and battery storage facility with 1 MW capacity; as well as AES Nejapa, a biomass power plant with 6 MW capacity; and 50% of Bosforo and Cuscatlan, solar farms with 100 MW and 10 MW capacity, respectively. The energy produced by these solar farms is fully contracted by AES' utilities in El Salvador.

In addition, AES El Salvador offers customers non-regulated services such as energy trading, electromechanical construction, O&M of electrical assets, EPC, pole rental, and tax collection for municipalities.

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

•operational performance;

•regulatory outcomes and impacts;

•variability in energy demand driven by weather; and

•the impact of fuel oil prices on energy tariff prices, which affect cash flow due to a three-month delay in the pass-through of energy costs to the tariffs charged to customers.

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


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


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Energy Infrastructure

Our Energy Infrastructure SBU aims to provide energy security to enable the integration of new renewables and maximize the value of our gas generation and LNG business through flexible operations that support the energy transition. This segment comprises generation facilities using natural gas, LNG, coal, pet coke, diesel, and/or oil, in nine countries — Vietnam, the United States, Argentina, Chile, Bulgaria, Mexico, Jordan, Panama, and the Dominican Republic.

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


Business	Location	Fuel	Gross MW	AES Equity Interest		Year Acquired or Began Operation	Contract Expiration Date	Customer(s)
Mong Duong 2	Vietnam	Coal	1,242	51	%	2015	2040	EVN
Southland—Alamitos	US-CA	Gas	1,200	100	%	1998	2026	California Department of Water Resources
Paraná-GT	Argentina	Gas/Diesel	870	100	%	2001
Southland Energy—Huntington Beach	US-CA	Gas	694	50	%	2020	2040	Southern California Edison
Southland Energy—Alamitos	US-CA	Gas	693	50	%	2020	2040	Southern California Edison
San Nicolás	Argentina	Coal/Gas/Oil/Energy Storage	691	100	%	1993
Maritza	Bulgaria	Coal	690	100	%	2011	2026	National Electric Company (NEK)
Gatun (1)	Panama	Gas	670	24	%	2024	2049	ENSA, Edemet, Edechi
TermoAndes (2)	Argentina	Gas/Diesel	643	99	%	2000	2025	Various
Guillermo Brown (3)	Argentina	Gas/Diesel	576	—	%	2016
Angamos	Chile	Coal	558	99	%	2011		Various
Cochrane (4)	Chile	Coal	550	97	%	2016	2030-2037	SQM, Sierra Gorda, Quebrada Blanca
AES Puerto Rico	US-PR	Coal	524	100	%	2002	2027	PREPA
Merida III	Mexico	Gas/Diesel	505	75	%	2000	2026	SIMSA, Regulus, Ammper, Trade On, Atrias
Amman East (1)	Jordan	Gas	472	10	%	2009	2033	National Electric Power Company
Colon (5)	Panama	Gas	381	65	%	2018	2028	ENSA, Edemet, Edechi
DPP (Los Mina)	Dominican Republic	Gas	358	65	%	1996	2027	Ede Este, Ede Norte, Ede Sur, Non-Regulated Users
Andres (6)	Dominican Republic	Gas/Diesel	319	65	%	2003	2027	Ede Este, Ede Norte, Ede Sur, Non-Regulated Users
Termoeléctrica del Golfo (TEG)	Mexico	Pet Coke	275	99	%	2007	2027	CEMEX
Termoeléctrica del Penoles (TEP)	Mexico	Pet Coke	275	99	%	2007	2027	Peñoles
IPP4 (1)	Jordan	Gas	250	10	%	2014	2039	National Electric Power Company
Southland—Huntington Beach	US-CA	Gas	236	100	%	1998	2026	California Department of Water Resources
Sarmiento	Argentina	Gas/Diesel	33	100	%	1996
			12,705

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

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

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

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

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

(6)Plant also includes an adjacent regasification facility, as well as two LNG storage tanks: Andres with 70 TBTU, or an operating capacity of 160,000 m3 and Enadom with 50 TBTU, or an operating capacity of 120,000 m3. Enadom is an unconsolidated entity, accounted for as an equity affiliate.

U.S. Conventional Generation

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


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

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

Our non-qualifying facility ("non-QF") generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined under the Energy Policy Act of 1992, amending the Public Utility Holding Company Act (“PUHCA”). These businesses, subject to approval of FERC, have the right to sell power at market-based rates, either directly to the wholesale market or to a third-party offtaker such as a power marketer or utility/industrial customer. Under the Energy Policy Act and FERC's regulations, approval from FERC to sell wholesale power at market-based rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry, and that there is no opportunity for abusive transactions involving regulated affiliates of the seller.

The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by FERC, and regional regulation as defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional transmission grid and maintain organized markets for electricity. These rules, for the most part, govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion on U.S. regulatory matters.

AES Southland

Business Description — AES Southland is one of the largest generation operators in California by aggregate installed capacity, with an installed gross capacity of 2,823 MW at the end of 2025. The four coastal power plants comprising AES Southland are in areas that are critical for local reliability and play an important role in integrating the increasing amounts of renewable generation resources in California. The AES Southland Energy Infrastructure assets are composed of two once-through cooling ("OTC") power plants and two combined cycle gas-fired generation facilities. This critical infrastructure is uniquely situated to support California in its transition to renewables with baseload gas-fired generation sited at high-demand points of interconnection within the Los Angeles Basin.

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

The Southland OTC units are subject to a variety of rules governing water use and discharge. The units are required to comply with the more stringent of state or federal requirements. AES Southland's current plan is to comply with the SWRCB OTC Policy by shutting down and permanently retiring all remaining generating units that utilize OTC by the compliance dates included in the OTC Policy. See United States Environmental and Land-Use Legislation and Regulations—Cooling Water Intake for further discussion of AES Southland’s plans regarding the OTC Policy.

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

The contracts are Resource Adequacy Purchase Agreements (“RAPAs”) with annual energy tolling put options. If Southland Energy exercises the annual put option, all capacity, energy, and ancillary services will be sold


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

Key Financial Drivers — AES Southland's availability is one of the most important drivers of operations, along with market demand and prices for gas and electricity.

AES Puerto Rico

Business Description — AES Puerto Rico owns and operates a 524 MW coal-fired cogeneration plant representing approximately 9% of the installed capacity in Puerto Rico. This plant is fully contracted through a long-term PPA with PREPA expiring in 2027. AES Puerto Rico receives a capacity payment based on the plants' twelve month rolling average availability, receiving the full payment when the availability is 90% or higher. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPAs with PREPA.

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

AES Argentina and TermoAndes

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

AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2025, approximately 86% of the energy was sold in the wholesale electricity market and 14% was sold under contract by the TermoAndes power plant.

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

•forced outages;

•exposure to fluctuations of the Argentine peso;

•timely collection of FONINVEMEM installments and outstanding receivables (see Energy Markets and Regulatory Environment below);

•natural gas prices and availability for contracted generation at TermoAndes; and

•domestic energy demand and exports.

AES Vietnam

Business Description — Mong Duong 2 is a 1,242 MW gross coal-fired plant located in the Quang Ninh Province of Vietnam and was constructed under a BOT service concession agreement expiring in 2040. This is the first coal-fired BOT plant using pulverized coal-fired boiler technology in Vietnam. The BOT company has a PPA with EVN and a Coal Supply Agreement with Vinacomin, both expiring in 2040.

On November 29, 2023, AES executed an agreement to sell its entire 51% interest in the Mong Duong 2 plant. Given that the sale did not close by the deadline specified in the agreement, AES exercised its right to terminate the agreement and remains the owner of its entire 51% interest.

Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, the operating performance and availability of the facility.

Development Strategy — In Vietnam, we continue to advance the development of our Son My LNG terminal project, which has a design capacity of up to 9.6 million metric tonnes per annum, and the Son My 2 CCGT project, which has a capacity of about 2,250 MW.


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In September 2019, we received a formal approval as the government-mandated investor with 100% equity ownership in the Son My 2 CCGT project, and executed a statutory memorandum of understanding with Vietnam’s Ministry of Industry and Trade to continue developing the Son My 2 CCGT project under Vietnam’s Build-Operate-Transfer legal framework. In October 2019, we received formal approval as a government-mandated investor in the Son My LNG terminal project in partnership with PetroVietnam Gas. In September 2021, we signed a joint venture agreement with PetroVietnam Gas, and in April 2022, established Son My LNG Terminal LLC, in which AES has a 39% interest. In July 2023, Son My LNG Terminal LLC received approval of investment policy and as the government-approved investor from the Binh Thuan Provincial People’s Committee. The Son My 2 CCGT project will utilize the Son My LNG terminal project and will be its anchor customer.

AES Chile

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

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

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

•spot market prices (largely impacted by dry hydrological scenarios, forced outages, and international fuel prices);

•changes in current regulatory rulings altering the ability to pass through or recover certain costs;

•fluctuations of the Chilean peso;

•tax policy changes; and

•legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets.

Decarbonization — The Chilean government’s decarbonization plan includes the complete retirement of the SEN coal fleet by the end of 2040 and carbon neutrality by 2050. Following the issuance of Supreme Decree Number 42 on December 26, 2020 by the Ministry of Energy and per the disconnection and termination agreement signed with the Chilean government in June 2019, AES Andes accelerated the retirement, disposal, or shutdown of the following coal-fired plants:

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

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

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

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

AES Mexico

Business Description — The TEG and TEP pet coke-fired plants, located in Tamuin, San Luis Potosi, supply power to their offtakers under long-term PPAs expiring in 2027 with a 90% availability guarantee. TEG and TEP have successfully migrated from the legacy market to the new energy regime established by the Electric Industry Law of 2021 and both are operating according to ISO instructions.

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

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

•contracting levels, providing additional benefits from improved operational performance, including performance incentives and/or excess energy sales;


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

•improved operational performance and plant availability.

AES Panama

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

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

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

•changes in hydrology, which impacts the spot prices and exposes the business to variability in the cost of replacement power;

•fluctuations in commodity prices, mainly fuel oil and natural gas, which affect the cost of thermal generation and spot prices;

•constraints imposed by the capacity of transmission lines connecting the west side of the country with the load, keeping surplus power trapped during the rainy season; and

•country demand, as GDP growth is expected to remain strong over the short and medium term.

Development Strategy — Given our LNG facility’s excess capacity in Panama, the company is developing natural gas supply solutions for third parties such as power generators and industrial and commercial customers. This strategy will support a growing demand for natural gas in the region and will contribute to AES' mission by reducing CO2 emissions as a result of using LNG.

AES Dominicana

Business Description — AES Dominicana has two operating subsidiaries within the Energy Infrastructure SBU, Andres and Los Mina, both of which are owned 65% by AES. With a total of 679 MW of installed thermal capacity, AES provides 9% of the country's capacity and supplies approximately 16% of the country's energy demand via these generation facilities. 575 MW are contracted with government-owned distribution companies.

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

Andres owns and operates a combined cycle natural gas turbine and an energy storage facility with combined generation capacity of 329 MW, as well as the only LNG import terminal in the country, with 160,000 cubic meters of storage capacity. Los Mina owns and operates a combined cycle facility with two natural gas turbines and an energy storage facility with combined generation capacity of 368 MW.

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

AES partnered with Energas in a joint venture to operate the 50 km Eastern Pipeline and an LNG facility of 120,000 cubic meters, including additional storage, regasification, and truck loading capacity.

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


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•changes in spot prices due to fluctuations in commodity prices (since fuel is a pass-through cost under the PPAs, any variation in oil prices will impact spot sales for Andres and Los Mina);

•expiring PPAs, lower contracting levels, and the extent of capacity awarded; and

•growth in domestic natural gas demand, supported by new infrastructure such as the Eastern Pipeline and second LNG tank.

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

AES Bulgaria

Business Description — Our AES Maritza plant is a 690 MW lignite fuel thermal power plant. AES Maritza's entire power output is contracted with NEK, the state-owned public electricity supplier, independent energy producer, and trading company. Maritza is contracted under a 15-year PPA that expires in May 2026. AES Maritza is collecting receivables from NEK in a timely manner. However, NEK's liquidity position is subject to political conditions and regulatory changes in Bulgaria.

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

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

•regulatory changes in the Bulgarian power market;

•results of the DG Comp review;

•availability and load factor of the operating units; and

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

AES Jordan

Business Description — In Jordan, AES has a 10% ownership interest in Amman East, a 472 MW oil/gas-fired plant fully contracted with the national utility under a 25-year PPA expiring in 2033, and a 10% ownership interest in the IPP4 plant, a 250 MW oil/gas-fired peaker plant fully contracted with the national utility until 2039. Following the sale of approximately 26% ownership interest in both plants in March 2024, Amman East and IPP4 were deconsolidated and are accounted for as equity method investments.


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New Energy Technologies

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

Fluence, the AI Fund, and Uplight are unconsolidated entities and their results are reported in Net equity in losses of affiliates on our Consolidated Statements of Operations. 5B is accounted for using the measurement alternative and AES will record income or loss only when it receives dividends from 5B or when there is a change in the observable price or an impairment of the investment. AES has a 100% ownership interest in Maximo, a consolidated entity.

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

Fluence

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


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

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

Development Strategy — The grid-connected energy storage sector is undergoing rapid expansion. By incorporating energy storage across the electric power network, utilities and communities around the world will optimize their infrastructure investments, increase network flexibility and resiliency, and accelerate cost-effective integration of renewable electricity generation. The global utility scale market, excluding China, will add approximately 3,201 GWh of energy storage capacity between 2024 and 2035, according to the Bloomberg NEF 2H 2025 Energy Storage Market Outlook, published in October 2025. Additional growth opportunities exist in providing operational and maintenance services associated with energy storage products, as well as the provision of digital applications and solutions to improve performance and economic output. Fluence is positioned to be a leading participant in this growth, with 7.2 GW of energy storage assets deployed and 9.7 GW of contracted backlog, with a gross global pipeline of 41.8 GW as of December 31, 2025.

Maximo

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

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

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

AI Fund

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

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

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


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Energy Markets and Regulatory Environment

Chile

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

Chile operates in a single power market, referred to as the SEN, which is managed by the grid operator Coordinador Electrico Nacional ("CEN"). The SEN has an installed capacity of 34,931 MW and represents 99% of the installed generation capacity of the country.

CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost. In the south-central region of the SEN, thermoelectric generation is required to fulfill demand not satisfied by hydroelectric, solar, and wind output and is critical to provide reliable and dependable electricity supply under dry hydrological conditions in the highest demand area of the SEN. In the northern region of the SEN, which includes the Atacama Desert, solar capacity represents the majority of installed capacity. The fuels used for thermoelectric generation, mainly coal, diesel, and LNG, are indexed to international prices. In 2025, the installed capacity in the Chilean market was composed of thermoelectric (36%), solar (30%), hydroelectric (21%) and wind (13%) generation.

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

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

All generators can sell energy through contracts with regulated distribution companies or directly to unregulated customers. Customers whose connected demand capacity is higher than 5 MW are excluded from the regulated market and are referred to as unregulated customers. Customers with connected capacity between 0.3 MW and 5 MW can opt for regulated or unregulated contracts for a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all electricity under contracts. Generators may also sell energy to other power generation companies on a short-term basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in USD, although payments are made in Chilean pesos.

In addition to energy payments, generators also receive capacity payments to compensate for availability during periods of peak demand. CEN annually determines the capacity requirements for each power plant. The capacity price is fixed semiannually by the National Energy Commission and indexed to CPI and other relevant indices.

Dominican Republic

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

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

•The National Energy Commission drafts and coordinates the legal framework and regulatory legislation. They propose and adopt policies and procedures to implement best practices, support the proper functioning and development of the energy sector, and promote investment.

•The Superintendence of Electricity's main responsibilities include monitoring compliance with legal provisions, rules, and technical procedures governing generation, transmission, distribution, and commercialization of electricity. They monitor behavior in the electricity market in order to prevent monopolistic practices.

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


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

El Salvador

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

•The National Energy and Hydrocarbons Direction is the highest authority on energy policy and strategy, and the coordinating body for the different energy sectors. One of its main objectives is to promote investment in non-conventional renewable sources to diversify the energy matrix.

•The General Superintendence of Electricity and Telecommunications regulates the market and sets consumer prices, and, jointly with the distribution companies in El Salvador, developed the tariff calculation originally applicable from 2023 until 2027.

AES El Salvador distribution rates are regulated by the General Superintendence of Electricity and Telecommunications and are established through a traditional cost-based rate-setting process. AES El Salvador is permitted to recover its costs of providing distribution services as well as earn a regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base, capital structure, and cost of capital. El Salvador has a national electric grid that interconnects directly with Guatemala and Honduras, allowing transactions with all Central American countries. The sector has approximately 2,563 MW of installed capacity, composed of thermal (53%), hydroelectric (24%), biomass (11%), solar (10%), and wind (2%) generation.

Bulgaria

The electricity sector in Bulgaria is regulated by the Bulgarian Energy Act. The Bulgarian electricity market allows both regulated and competitive segments. NEK ceased to be the public provider of electricity at the end of June 2025. From July 2025 onwards, Bulgarian distribution companies serving the regulated market are sourcing their electricity needs exclusively from a special segment of the market where NEK is the main supplier through their energy mix (consisting of NEK-owned HPPs, NPP Kozlodui, state owned TPP Maritza East 2, and AES Maritza). Electricity outside the regulated market trades on one of the platforms of the Independent Bulgarian Electricity Exchange day-ahead market, intra-day market, or bilateral contracts market.

Bulgaria’s power sector is supported by a diverse generation mix, universal access to the grid, and numerous cross-border connections with neighboring countries. In addition, it plays an important role in the energy balance in the southeast European region.

Bulgaria has 17 GW of installed capacity enabling the country to meet and exceed domestic demand and export energy. Installed capacity is primarily composed of solar (34%), thermal (31%), hydro (19%), and nuclear (12%) generation.

Panama

The Panamanian power sector is composed of three distinct operating business units: generation, distribution, and transmission. Generators can enter into short-term and long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into backup supply contracts with each other. Outside of PPAs, generators may buy and sell energy in the short-term market. Generators can only contract up to their firm capacity.

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

•The National Secretary of Energy in Panama ("SNE") has the responsibilities of planning, supervising, and controlling policies of the energy sector within Panama. The SNE proposes laws and regulations to the executive agencies that regulate the procurement of energy and hydrocarbons for the country.

•The National Authority of Public Services ("ASEP") is an autonomous agency of the government. ASEP is responsible for the regulations, control, and oversight of public services in Panama, including electricity, the transmission and distribution of natural gas utilities, and the companies that provide such services.

•The National Dispatch Center ("CND") is in charge of the operation of the system and the management of the electricity market. They are responsible for implementing the economic dispatch of electricity in the wholesale market. The National Dispatch Center's objectives are to minimize the total cost of generation and maintain the reliability and security of the electric power system. Short-term power prices are


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determined on an hourly basis by the last dispatched generating unit. Physical generation of energy is determined as a result of the optimization of the economic dispatch regardless of contractual arrangements.

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

Mexico

Mexico's main electrical system is called the National Interconnected System, which geographically covers an area from Puerto Peñasco, Sonora to Cozumel, Quintana Roo. Mexico also has three isolated electrical systems: (1) the Baja California Interconnected System, which is interconnected with the western interconnection; (2) the Baja California Sur Interconnected System; and (3) the Mulegé Interconnected System. All three are isolated from the SIN and from each other. The Mexican power industry comprises the activities of generation, transmission, distribution, and commercialization segments, considering transmission and distribution to be exclusive state services.

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

In addition to the Ministry of Energy, three main agencies are responsible for regulating market agents and their activities, monitoring compliance with laws and regulations, and surveillance of operational compliance and management of the wholesale electricity market:

•The Energy Regulatory Commission is responsible for the establishment of directives, orders, methodologies, and standards to regulate the electric and fuel markets, as well as granting permits.

•The National Center for Energy Control, as an ISO, is responsible for managing the wholesale electricity market, transmission and distribution infrastructure, planning network developments, guaranteeing open access to network infrastructure, executing competitive mechanisms to cover regulated demand, and setting transmission charges.

•The Electricity Federal Commission ("CFE") owns the transmission and distribution grids and is also the country's basic supplier. CFE is the offtaker for IPP generators, and together with its own power units has more than 50% of the current generation market share.

Mexico has an installed capacity of 92 GW, composed of thermal (64%), hydroelectric (14%), solar (8%), wind (8%), and other fuel (6%) generation.

Argentina

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

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

The Argentine regulatory framework divides the electricity sector into generation, transmission, and distribution. The wholesale electric market is comprised of generation companies, transmission companies, distribution companies, and large customers who are permitted to trade electricity. Generation companies can sell their output in the spot market or under PPAs. CAMMESA manages the electricity market and is responsible for dispatch coordination. The Electricity National Regulatory Agency is in charge of regulating public service activities and the Secretariat of Energy regulates system framework and grants concessions or authorizations for sector activities.

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


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

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

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

In past years, AES Argentina contributed certain accounts receivable to fund the construction of three power plants under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over 10 years after the commercial operations date of the related plant. In 2020, FONINVEMEM I and II installments were fully repaid and in 2021 the ownership interests in Termoeléctrica San Martín and Termoeléctrica Manuel Belgrano were defined after the incorporation of the National Government as majority shareholder. The transfer of the power plants to these companies has not yet occurred. FONINVEMEM III is related to Termoeléctrica Guillermo Brown, which began operations in April 2016, and the installments are still being collected. AES Argentina will receive a pro rata ownership interest in this plant, not to exceed 30%, once the accounts receivable have been fully repaid.

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

Colombia

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

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

The generation sector is organized on a competitive basis with companies selling their generation in the wholesale market at the short-term price or under bilateral contracts with other participants, including distribution companies, generators and traders, and unregulated customers at freely negotiated prices. The National Dispatch Center dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the lowest cost combination of available generating units.

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

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


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Vietnam

The Ministry of Industry and Trade in Vietnam is primarily responsible for formulating a program to restructure the power industry, developing the electricity market, and promulgating electricity market regulations. The fuel supply is owned by the government through Vinacomin, a state-owned entity, and PetroVietnam.

The Vietnam power market is divided into three regions (North, Central, and South), with total installed capacity of approximately 82 GW. The fuel mix in Vietnam is composed primarily of coal (32%), hydroelectric (29%) and renewables generation, including solar, wind, and biomass (26%). EVN, the national utility, owns 38% of installed generation capacity.

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

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

Puerto Rico

Puerto Rico has a single electric grid managed by PREPA, a state-owned entity that provides virtually all of the electric power consumed in Puerto Rico and generates, transmits, and distributes electricity to 1.5 million customers. Since June 2021, PREPA has contracted LUMA Energy to manage the transmission, distribution, and commercialization activities. The Puerto Rico Energy Bureau is the main regulatory body. The bureau approves wholesale and retail rates, sets efficiency and interconnection standards, and oversees PREPA's compliance with Puerto Rico's renewables portfolio standard.

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

Jordan

The Jordan electricity transmission market is a single-buyer model with the state-owned National Electric Power Company ("NEPCO") responsible for transmission. NEPCO generally enters into long-term PPAs with IPPs to fulfill energy procurement requests from distribution utilities.

U.S. Utilities

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


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Environmental and Land-Use Regulations

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

Many of the countries in which the Company does business have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from electric power generation or distribution assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are subject to World Bank environmental standards or similar standards, which tend to be more stringent than local country standards. The Company has often used advanced generation technologies in order to minimize environmental impacts, such as combined fluidized bed boilers and advanced gas turbines, and environmental control devices such as flue gas desulphurization for SO2 emissions and selective catalytic reduction for NOx emissions.

Environmental laws and regulations affecting electric power generation and distribution facilities are complex, change frequently, and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with these environmental laws and regulations. The Company may be required to make significant capital or other expenditures to comply with these regulations. There can be no assurance that the businesses operated by the subsidiaries of the Company will be able to recover any of these compliance costs from their counterparties or customers such that the Company's consolidated results of operations, financial condition, and cash flows would not be materially affected.

Various licenses, permits, and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions, or changes to our operations. Certain subsidiaries of the Company are subject to litigation or regulatory action relating to environmental permits or approvals. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect to environmental litigation and regulatory action.

United States Environmental and Land-Use Legislation and Regulations

In the United States, numerous environmental laws and regulations regulate emissions of SO2, NOX, particulate matter, GHGs, mercury, hazardous air pollutants, water discharges, waste management, and species and habitat protections. Certain applicable rules are discussed in further detail below.

CSAPR — CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment of, or interference with maintenance of, any NAAQS. The CSAPR is implemented in part through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA.

On June 5, 2023, the EPA published a final Federal Implementation Plan ("FIP") to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and Maryland, and became effective during 2023 and includes enhancements to the revised Group 3 trading program. On June 27, 2024, the U.S. Supreme Court issued an order granting a stay of the EPA’s 2023 FIP pending resolution of legal challenges to the FIP.


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On November 6, 2024, the EPA published an Interim Final Rule in the Federal Register in response to the U.S. Supreme Court’s stay of its FIP addressing interstate transport for the 2015 ozone national ambient air quality standards. The Interim Final Rule stays the effectiveness of the Good Neighbor FIP and revises the CSAPR regulations to continue application of the states’ respective trading programs. It is too early to determine the impact of this final rule, but it may result in the need to purchase additional allowances or make operational adjustments.

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

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

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

Regional Haze Rule — The EPA's "Regional Haze Rule" established timelines for states to improve visibility in national parks and wilderness areas throughout the United States by establishing reasonable progress goals toward meeting a national goal of natural visibility conditions in Class I areas by the year 2064 through a series of state implementation plans ("SIPs"), which may result in additional emissions control requirements for electric generating units. SIPs for the first planning period (through 2018) did not result in material impact to AES facilities. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. The deadline for submittal of the SIP covering the second planning period was July 31, 2021. On October 2, 2025, the EPA published an advanced notice of proposed rulemaking requesting public input on potential future changes to the Regional Haze Rule. On January 6, 2026, the EPA published a final rule extending the deadline for states to submit implementation plans for the third planning period from July 31, 2028 to July 31, 2031. To date, none of the states in which we operate have submitted plans that identify potential impacts to Company facilities. However, we cannot predict the possible outcome or potential impacts of this matter at this time.

NAAQS — Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOX, and SO2, which result from fossil-fuel combustion. Areas meeting the NAAQS are designated "attainment areas" while those that do not meet the NAAQS are considered "nonattainment areas." Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.

Based on the current and potential future ambient air standards, certain of the states in which the Company's subsidiaries operate have determined or will be required to determine whether certain areas within such states meet the NAAQS. Some of these states may be required to modify their SIPs to detail how the states will attain or maintain their attainment status. As part of this process, it is possible that the applicable state environmental regulatory agency or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter, NOX, or SO2. The compliance costs of the Company's U.S. subsidiaries could be material.


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

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

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

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

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

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

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

As such, there is some uncertainty with respect to the impact of GHG rules. The NSPS for new EGUs will not require us to comply with an emissions standard until we construct a new electric generating unit. We do not have any planned major modifications of an existing source or plans to construct a new major source at this time which are expected to be subject to these regulations. Furthermore, the EPA, states, and other utilities are still evaluating potential impacts of the GHG regulations in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows, and financial condition.

Due to the future uncertainty of these regulations and associated litigation, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with a new Section 111(d) Rule, should it be implemented in a prior or a substantially similar form, could be material. The GHG NSPS for new EGUs remains in effect at this time, and absent further action from the EPA that rescinds or substantively revises the NSPS, it could impact any Company plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition, or results of operations.


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Cooling Water Intake — The Company's facilities are subject to a variety of rules governing water use and discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA effective in 2014 that seeks to protect fish and other aquatic organisms drawn into cooling water systems at power plants and other facilities. These standards require affected facilities to choose among seven best technology available ("BTA") options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible that this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment. It is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.

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

Power plants are required to comply with the more stringent of state or federal requirements. At present, the California state requirements are more stringent and have earlier compliance dates than the federal EPA requirements, and are therefore applicable to the Company's California assets. The Company anticipates that compliance with CWA Section 316(b) regulations and associated costs could have a material impact on our consolidated financial condition or results of operations.

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

On September 8, 2023, the Agencies published the “Revised Definition of ‘Waters of the United States’” rule. This final rule amendment conforms the definition to the definition adopted in the Decision. On March 12, 2025, the Agencies issued a joint guidance memorandum for implementing the “continuous surface connection” consistent with the Decision and related issues. On March 24, 2025, the Agencies published notice outlining a process to gather recommendations for implementation of WOTUS. On November 20, 2025, the Agencies proposed revisions to align the definition of WOTUS with the Decision to clarify federal jurisdiction under CWA. It is too early to determine whether the outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over WOTUS may have a material impact on our business, financial condition, or results of operations.

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash, and more stringent effluent limitations for flue gas desulfurization wastewater. AES Indiana Petersburg has installed a dry bottom ash handling system in response to the CCR rule and wastewater treatment systems in response to the NPDES permits in advance of the ELG compliance date. Other U.S. businesses already include dry handling of fly ash and bottom ash and do not generate flue gas desulfurization wastewater. Following the 2019 U.S. Court of Appeals vacatur and remand of portions of the 2015 ELG rule related to leachate and legacy water, on March 29, 2023, the EPA published a proposed rule revising the 2020 Reconsideration Rule. On May 9, 2024, the EPA published a final rule which became effective on July 8, 2024. The final rule established more stringent best available technology limits for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate and established a new set of definitions and new limits for combustion residual leachate and legacy wastewater. The May 2024 rule


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is subject to legal challenges. On October 10, 2024, the Eighth Circuit Court denied stay applications. On October 2, 2025, the EPA published a proposed rule that, if finalized, would extend certain ELG deadlines and allow facilities to choose between compliance alternatives. On the same date, the EPA also published a direct final rule to extend the deadline for power plants to file a notice of planned participation for the permanent cessation of coal from December 31, 2025, to December 31, 2031 pending any significant adverse comments. On November 28, 2025, the EPA withdrew the direct final rule due to receipt of adverse comments. On December 31, 2025, EPA published a final rule that extended ELG deadlines for bottom ash transport water, flue gas desulfurization wastewater, and combustion residual leachate, allowed facilities to choose between compliance alternatives, and extended the deadline for power plants to file a notice of planned participation for the permanent cessation of coal from December 31, 2025, to December 31, 2031. The rule is subject to legal challenges. It is too early to determine whether any outcome of litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition, and results of operations.

On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of "functional equivalent" are ongoing in various jurisdictions. On November 27, 2023, the EPA issued a draft guidance addressing how the Supreme Court decision would be applied to the NPDES permit program as it relates to functional equivalent discharge. However, in February 2025, the EPA pulled back the guidance before it cleared the Office of Management and Budget. It is too early to determine whether the Supreme Court decision or the result of litigation to "functional equivalent" may have a material impact on our business, financial condition, or results of operations.

Waste Management — On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and existing CCR landfills and CCR surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. The 2016 Water Infrastructure Improvements for the Nation Act ("WIN Act") includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. If this rule is finalized before Indiana or Puerto Rico establishes a state-level CCR permit program, AES CCR units in those locations could eventually be required to apply for a federal CCR permit from the EPA. Following prior rulemaking development and comment periods, on December 18, 2025, the Indiana Environmental Rules Board adopted a final CCR rule that includes regulation of CCR through a state permitting program. The rule and permitting program would become effective upon approval by the EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

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

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

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


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

International Environmental Regulations

Chile

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

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

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

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

Bulgaria

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

Argentina

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

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

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

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

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


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Colombia

Decree 1076 of 2015 established the current Environmental Licensing Scheme that defines the scope of the National Environmental Licensing Authority ("ANLA") for granting environmental licenses. In recent years, the Ministry of the Environment has generated regulations in connection with licenses, such as the biotic compensation methodology and guidance for presentation of environmental studies in 2018, and the regulation of minor changes to environmental licenses in 2022. As a result of the introduction of non-conventional renewable energy projects, various regulations were issued regarding the environmental permits applicable to these types of projects and the participation of indigenous communities in environmental licensing processes.

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

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

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

At the end of 2023, AES Colombia obtained the environmental license, issued by the ANLA, for the 500 kV line to connect the Guajira pipeline projects. Currently, AES Colombia has obtained environmental licenses for 406 MW of wind projects in Guajira. During 2025, ANLA issued an environmental license modification for the connection line to cover the complete infrastructure of the project and started the environmental licensing process for the Jemeiwaa Ka’I 4 wind project.

Customers

We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2025 total revenue. In our generation business, we own and/or operate power plants to sell power to wholesale customers such as utilities and other intermediaries, as well as to large corporations. Our utilities sell to end-user customers in the residential, commercial, industrial, and governmental sectors in a defined service area.

Human Capital Management

At AES, our people are instrumental to helping us meet the world’s energy needs. Supporting our people is a foundational value for AES. Our actions are grounded in the shared values that shape AES’ culture: Safety First, Highest Standards, and All Together. The AES Corporation is led and managed by our Chief Executive Officer and the Global Leadership Team with the guidance and oversight of our Board of Directors. Governance and standards for AES people are guided by the Chief Human Resources Officer, with input from members of the Global Leadership Team.

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

As of December 31, 2025, approximately 31% of our U.S. employees were subject to collective bargaining agreements. Collective bargaining agreements between us and these labor unions expire at various dates ranging


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from 2026 to 2027. In addition, certain employees in non-U.S. locations were subject to collective bargaining agreements, representing approximately 48% of the non-U.S. workforce. As of December 31, 2025, approximately 25% of our U.S. and non-U.S. workforce is part of bargaining agreements expiring on or before December 31, 2026. Management believes that the Company's employee relations are favorable.

Safety

At AES, safety is one of our core values. Conducting safe operations at our facilities around the world, so that each person can return home safely, is the cornerstone of our daily activities and decisions. Safety efforts are led by our Chief Operating Officer and supported by safety committees that operate at the local site level. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety.

AES has established a Safety Management System (“SMS”) Global Safety Standard that applies to all AES employees, as well as contractors working in AES facilities and construction projects. The SMS requires continuous safety performance monitoring, risk assessment, and performance of periodic integrated environmental, health, and safety audits. The SMS provides a consistent framework for all AES operational businesses and construction projects to set expectations for risk identification and reduction, measure performance, and drive continuous improvements. The SMS standard is consistent with the ISO 45001 standard, and during 2025 approximately 48% of our locations (excluding renewable assets in the United States, more than 80% of which are smaller than 20 MW) have elected to formally certify their SMS to the ISO 45001 international standard. AES calculates lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards, based on 200,000 labor hours, which equates to 100 workers who work 40 hours per week and 50 weeks per year. In 2025, there was an 11% decrease in AES' LTI cases. In 2025, AES’ LTI Rate was 0.086 for AES People, 0.118 for operational contractors, and 0.000 for construction contractors. In 2025, the Company did not have any work-related fatalities.

Talent

We believe AES’ success depends on its ability to attract, develop, and retain key personnel. The skills, experience, and industry knowledge of key employees significantly benefit our operations and performance. We have a comprehensive approach to managing our talent and developing our leaders in order to ensure our people have the right skills for today and tomorrow, whether that requires us to build new business models or leverage leading technologies.

We emphasize employee development and training. To empower employees, we provide a range of development programs and opportunities, skills, and resources they need to be successful by focusing on experience and exposure, as well as formal programs including our Trainee Program.

Compensation

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

Executive Officers

The following individuals are our executive officers:

Stephen Coughlin, 54 years old, has served as Executive Vice President and Chief Financial Officer since October 2021. Prior to assuming his current position, he led AES’ Corporate Strategy and Financial Planning teams, and served as the Chair of the Company’s Investment Committee. Prior to that role, he served as the Chief Executive Officer of Fluence. Mr. Coughlin joined AES in 2007 and spent his early years with the company leading Financial Planning & Analysis for AES’ renewables portfolio. Mr. Coughlin is a member of the boards of AES Clean Energy Development Holdings, LLC, AES U.S. Investments, Inc., and IPALCO. Mr. Coughlin received a bachelor's


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degree in commerce and finance from the University of Virginia and a Master of Business Administration degree from the University of California at Berkeley.

Bernerd Da Santos, 62 years old, has served as Executive Vice President and President of the Renewables SBU since June 2023. Previously, Mr. Da Santos held several positions at AES, including Chief Operating Officer and Executive Vice President from December 2017 to July 2023, Chief Operating Officer and Senior Vice President from 2014 to 2017, Chief Financial Officer, Global Finance Operations from 2012 to 2014, Chief Financial Officer of Global Utilities from 2011 to 2012, Chief Financial Officer of Latin America and Africa from 2009 to 2011, Chief Financial Officer of Latin America from 2007 to 2009, Managing Director of Finance for Latin America from 2005 to 2007, and VP and Controller of La Electricidad de Caracas (“EDC”) (Venezuela). Prior to joining AES in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos is President and Chief Executive Officer of AES Clean Energy Development, and a member of the boards of IPALCO, AES Andes, AES Mong Duong Power Co. Ltd., and Son My LNG Terminal LLC. Mr. Da Santos holds a bachelor’s degree with Cum Laude distinction in Business Administration and Public Administration from Universidad José Maria Vargas, a bachelor’s degree with Cum Laude distinction in Business Management and Finance, and an MBA with Cum Laude distinction from Universidad José Maria Vargas.

Ricardo Manuel Falú, 46 years old, was appointed President effective March 2, 2026. Prior to assuming his current position, Mr. Falú served as Executive Vice President and Chief Operating Officer since February 2024, Senior Vice President and Chief Operating Officer from July 2023 to February 2024 and Senior Vice President and Chief Strategy and Commercial Officer from August 2022 to July 2023. From March 2023 to March 2026, Mr. Falú also served as President of the New Energy Technologies SBU. Mr. Falú joined AES in 2003 and, prior to his current roles, served as President of the Andes region from January 2022 to August 2022 and Chief Executive Officer of AES Andes from April 2018 to August 2022, which includes AES Chile, AES Colombia, and AES Argentina. Before that, Mr. Falú served as the Chief Financial Officer for the Company's businesses in the Andes region from 2014 to April 2018 and as Chief Financial Officer for the Company's businesses in the Mexico, Central American, and Caribbean region from 2012 to 2014. He is a member of the boards of IPALCO, Fluence Energy, Inc., AES Andes, DPL, and AES Colombia. Prior to joining AES, Mr. Falú worked as an external auditor, accounting analyst, and financial consultant in Argentina. He holds a Certified Public Accountant degree from the Universidad Nacional de Salta in Argentina and an Executive MBA, graduating Summa Cum Laude from the IAE Business School. He also holds a diploma from the Wharton Advanced Management Program, a Certificate in Management from Darden, and has completed other executive financial and management studies at Darden, Wharton, and Harvard.

Paul L. Freedman, 56 years old, has served as Executive Vice President, General Counsel, and Corporate Secretary since February 2021. Prior to assuming his current position, Mr. Freedman was Senior Vice President and General Counsel from February 2018, Corporate Secretary from October 2018, Chief of Staff to the Chief Executive Officer from April 2016 to February 2018, Assistant General Counsel from 2014 to 2016, and from 2007 to 2014 he held a variety of other positions in the AES legal group. Mr. Freedman is a member of the Boards of, AES U.S. Investments, Inc., IPALCO, and AES Southland Energy Holdings, LLC. Additionally, Mr. Freedman is a member of the Boards of the Business Council for International Understanding and the Coalition for Integrity. Prior to joining AES, Mr. Freedman was Chief Counsel for credit programs at the U.S. Agency for International Development and he previously worked as an associate at the law firms of White & Case and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center.

Andrés R. Gluski, 68 years old, has been Chief Executive Officer and a member of our Board of Directors since September 2011 and is a member of the Innovation and Technology Committee. He also served as President from September 2011 to March 2026. Under his leadership, AES has become a world leader in implementing clean technologies, including energy storage and renewable power. Prior to assuming his current position, Mr. Gluski served as Executive Vice President and Chief Operating Officer of the Company from 2007 to 2011. Prior to that role, he served in a number of senior roles at AES, including as Regional President of Latin America and was Senior Vice President for the Caribbean and Central America. He is a member of the Board of Waste Management and serves as Chairman of the Americas Society/Council of the Americas. Mr. Gluski is a magna cum laude graduate of Wake Forest University and holds an M.A. and a Ph.D. in Economics from the University of Virginia.

Tish Mendoza, 50 years old, has served as Executive Vice President and Chief Human Resources Officer since February 2021. Prior to assuming her current position, Ms. Mendoza was Senior Vice President, Global Human Resources and Internal Communications and Chief Human Resources Officer from 2012, Vice President of Human Resources, Global Utilities from 2011 to 2012, Vice President of Global Compensation, Benefits and HRIS, including Executive Compensation, from 2008 to 2011, and acted in the same capacity as the Director of the


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function from 2006 to 2008. Ms. Mendoza is a member of the boards of IPALCO, and Fluence Energy, Inc., and sits on AES’ compensation and benefits committees. Prior to joining AES, Ms. Mendoza was Vice President of Human Resources for a product company in the Treasury Services division of JP Morgan Chase and Vice President of Human Resources and Compensation and Benefits at Vastera, Inc., a former technology and managed services company. Ms. Mendoza earned certificates in Leadership and Human Resource Management, and a bachelor’s degree in Business Administration and Human Resources.

Juan Ignacio Rubiolo, 49 years old, was appointed as Executive Vice President, Chief Operating Officer and President of the Energy Infrastructure SBU effective March 2, 2026. Prior to assuming his current position, Mr. Rubiolo served as Executive Vice President and President of the Energy Infrastructure SBU since March 2023, Executive Vice President and President of International Businesses from January 2022 to March 2023, Senior Vice President and President of the MCAC SBU from March 2018 to January 2022, as the Chief Executive Officer of AES Mexico from 2014 to March 2018, and as a Vice President of the Commercial team of the MCAC SBU from 2013 to 2014. Mr. Rubiolo joined AES in 2001 and has worked in AES businesses in the Philippines, Argentina, Mexico, Panama, and the Dominican Republic. Mr. Rubiolo serves on the boards of AES Andes, and AES Colombia. Mr. Rubiolo has a Science Degree in Business from the Universidad Austral of Argentina, a Master of Project Management from the Quebec University in Canada and has completed the executive business and leadership program at the University of Virginia.

How to Contact AES and Sources of Other Information

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

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

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

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

ITEM 1A. RISK FACTORS

You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations. We routinely encounter and address risks, some of which may cause our future results to be materially different than we presently anticipate. The categories of risk we have identified in Item 1A.—Risk Factors include risks associated with our operations, governmental regulation and laws, our indebtedness and financial condition. These risk factors should be read in conjunction with Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K and the Consolidated Financial Statements and related notes included elsewhere in this Form 10-K. If any of the following events actually occur, our business, financial results and financial condition could be materially adversely affected.


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Risks Associated with our Operations

The operation of power generation, distribution and transmission facilities involves significant risks.

We are in the business of generating and distributing electricity, which involves certain risks that can adversely affect financial and operating performance, including:

•changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, failure of transmission systems, labor disputes, disruptions in fuel supply, poor hydrologic and wind conditions, inability to comply with regulatory or permit requirements, or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, dam failures, tsunamis, explosions, terrorist acts, vandalism, cyber-attacks or other similar occurrences; and

•changes in our operating cost structure, including, but not limited to, increases in costs relating to gas, coal, oil, and other fuel; fuel transportation; purchased electricity; operations, maintenance, and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.

Our businesses require reliable transportation sources (including related infrastructure such as roads, ports, and rail), power sources and water sources to access and conduct operations. The availability and cost of this infrastructure affects capital and operating costs and levels of production and sales. Limitations or interruptions in this infrastructure or at the facilities of our subsidiaries, including as a result of third parties intentionally or unintentionally disrupting this infrastructure or the facilities of our subsidiaries, could impede their ability to produce electricity.

In addition, a portion of our generation facilities were constructed many years ago and may require significant capital expenditures for maintenance. The equipment at our plants requires periodic upgrading, improvement or repair and replacement equipment or parts may be difficult to obtain in circumstances where we rely on a single supplier or a small number of suppliers. The inability to obtain replacement equipment or parts, due to disruption of the supply chain or other factors, may impact the ability of our plants to perform. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of a power purchase or other agreement or incurrence of a liability for liquidated damages and/or other penalties.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error, or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.

In addition, our battery storage operations also involve risks associated with lithium-ion batteries. On rare occasions, lithium-ion batteries can rapidly release the energy they contain by venting smoke and flames in a manner that can ignite nearby materials as well as other lithium-ion batteries. While more recent design developments for our storage projects seek to minimize the impact of such events, these events are inherent risks of our battery storage operations.

The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant, and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties.

Furthermore, we and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.— Legal Proceedings below. There can be no assurance that the outcomes of such matters will not have a material adverse effect on our consolidated financial position.


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Our renewable energy projects and other initiatives face considerable uncertainties.

Wind, solar, and energy storage projects are subject to substantial risks. In particular, in the U.S., AES’ renewable energy generation growth strategy has depended in part on federal, state, and local government policies and incentives that support the development, financing, ownership, and operation of renewable energy generation projects, including investment tax credits, production tax credits, accelerated depreciation, renewable portfolio standards, feed-in-tariffs, and similar programs, REC mechanisms and compliance programs, and tax exemptions. More recently, the favorable regulatory regimes associated with the U.S. Inflation Reduction Act of 2022 have been curtailed by the passage of H.R. 1 (the "2025 Act"). See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—U.S. Tax Law Reform and U.S. Renewable Energy Tax Credits. If these policies and incentives are further changed or eliminated, if pending tax guidance related to these policies is adverse, or AES is otherwise unable to use these policies or incentives, there could be a material adverse impact on AES’ U.S. renewable growth opportunities, including fewer future PPAs, decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. Further, the adoption of the 2025 Act requires the issuance of tax guidance, some of which has not yet been issued, that may further impact our projects.

In addition, new tariffs, duties, or other assessments have been imposed on the imports of solar cells, modules, batteries, or other equipment utilized in our renewable energy projects. Any such developments could impede the realization of our U.S. renewables strategy by resulting in, among other items, lack of a satisfactory market for the development and/or financing of our U.S. renewable energy projects, abandoning the development of certain U.S. renewable energy projects, a loss of our investments in the projects, and/or reduced project returns.

Furthermore, production levels for our wind and solar projects may be dependent upon adequate wind or sunlight resulting in volatility in production levels and profitability. For our wind projects, wind resource estimates are based on historical experience when available and on wind resource studies conducted by an independent engineer. These wind resource estimates are not expected to reflect actual wind energy production in any given year, but long-term averages of a resource.

As a result, these types of projects face considerable risk, including that favorable regulatory regimes are further adversely modified. At the development or acquisition stage, our ability to predict actual performance results may be hindered and the projects may not perform as predicted. There are also risks associated with the fact that some of these projects exist in markets where long-term fixed-price contracts for the major cost and revenue components may be unavailable, which in turn may result in these projects having relatively high levels of volatility. These projects can be capital-intensive and generally are designed with a view to obtaining third-party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop or obtain third-party financing for these projects.

Further, in the U.S., the tax credits associated with certain renewables projects are earned when the project is placed in service. Delays in executing our renewables projects can result in delays in recognizing those tax credits and adversely impact our short-term financial results.

Any of the above factors could have a material adverse effect on our business, financial condition, results of operations and prospects.

Our development projects are subject to substantial uncertainties.

We are in various stages of developing and constructing renewables projects and power plants. Certain of these projects have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion of the development of these projects depends upon overcoming substantial risks, including risks relating to siting, financing, engineering and construction, permitting, interconnection and transmission, governmental approvals, commissioning delays, supply chain related disruptions to our access to materials, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. Objections of or challenges by local communities or interest groups may delay or impede permitting for our development projects.

Additionally, in the U.S., there is a significant backlog of interconnection requests for renewables and battery storage projects and the average time for receiving interconnection approvals is over four years, with significant variations across projects and regions. Our existing interconnection requests may also be subject to regulatory changes that could negatively impact the timing or cost associated with obtaining interconnection approval. Some RTOs, such as PJM, have recently implemented or are considering accelerated or supplemental interconnection processes for high-capacity factor resources or for resources that service a resource adequacy need or new load,


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which could result in delays or cost increases to existing or future interconnection requests of intermittent renewable energy projects, such as solar and wind. Additional measures could be considered by RTOs, transmission owners, or governmental authorities to foster or accelerate deployment or utilization of certain high-capacity factor technologies in a manner that negatively impacts the development of solar or wind projects. There are also severe bottlenecks in the transmission system and the build-out of renewables to meet policy goals for renewable deployment will require substantial upgrades to the transmission network. These upgrades may also be delayed by the accelerated or supplemental interconnection of high-capacity factor resources, as discussed above.

In certain cases, our subsidiaries may enter into obligations in the development process even though they have not yet secured financing, PPAs, or other important elements for a successful project. For example, our subsidiaries may instruct contractors to begin the construction process or seek to procure equipment without having financing, a PPA or critical permits in place (or enter into a PPA, procurement agreement or other agreement without agreed financing).

If the project does not proceed, our subsidiaries may retain certain liabilities. Furthermore, we may undertake significant development costs and subsequently not proceed with a particular project. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance that any individual project will reach commercial operation. If development efforts are not successful, we may abandon certain projects, resulting in writing off the costs incurred, expensing related capitalized development costs incurred, and incurring additional losses associated with any related contingent liabilities.

We do a significant amount of business outside the U.S., including in developing countries.

A significant amount of our revenue is generated in developing countries, and we intend to expand our business in certain developing countries in which AES or its customers have an existing presence. International operations, particularly in developing countries, entail significant risks and uncertainties, including:

•economic, social, and political instability in any particular country or region;

•adverse changes in currency exchange rates;

•government restrictions on converting currencies or repatriating funds;

•unexpected changes in foreign laws and regulations or in trade, monetary, fiscal, or environmental policies;

•high inflation and monetary fluctuations;

•restrictions on imports of solar panels, wind turbines, coal, oil, gas, or other raw materials;

•threatened or consummated expropriation or nationalization of our assets by foreign governments;

•unexpected delays in permitting and governmental approvals;

•unexpected changes or instability affecting our strategic partners in developing countries;

•failure to comply with the U.S. Foreign Corrupt Practices Act, or other applicable anti-bribery regulations;

•unwillingness of governments, agencies, similar organizations, or other counterparties to honor contracts;

•unwillingness of governments, government agencies, courts, or similar bodies to enforce contracts that are economically advantageous to AES and less beneficial to government or private party counterparties, against those counterparties;

•inability to obtain access to fair and equitable political, regulatory, administrative, and legal systems;

•adverse changes in government tax policy and tax consequences of operating in multiple jurisdictions;

•difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local jurisdictions; and

•inability to attract and retain qualified personnel.

Developing projects in less developed economies also entails greater financing risks, and such financing may only be available from multilateral or bilateral international financial institutions or agencies that require governmental guarantees for certain project and sovereign-related risks. There can be no assurance that project financing will be available or that, once secured, will provide similar terms or flexibility as would be expected from a commercial lender.

Further, our operations may experience volatility in revenues and operating margin caused by regulatory and economic difficulties, political instability, and currency devaluations, which may increase the uncertainty of cash flows from these businesses.


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Any of these factors could have a material, adverse effect on our business, results of operations and financial condition.

Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets.

Some of our businesses sell or buy electricity in the spot markets when they operate at levels that differ from their power sales agreements or retail load obligations or when they do not have any powers sales agreements. Our businesses may also buy electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. The open market wholesale prices for electricity can be volatile and generally reflect the variable cost of the source generation which could include renewable sources at near zero pricing or thermal sources subject to fluctuating cost of fuels such as coal, natural gas, or oil derivative fuels in addition to other factors described below. Consequently, any changes in the generation supply stack and cost of coal, natural gas, or oil derivative fuels may impact the open market wholesale price of electricity.

Volatility in market prices for fuel and electricity may result from, among other things:

•plant availability in the markets generally;

•availability and effectiveness of transmission facilities owned and operated by third parties;

•competition and new entrants;

•seasonality, hydrology, and other weather conditions;

•illiquid markets;

•transmission, transportation constraints, inefficiencies, and/or availability;

•renewables source contribution to the supply stack;

•increased adoption of distributed generation;

•energy efficiency and demand side resources;

•available supplies of coal, natural gas, and crude oil and refined products;

•generating unit performance;

•natural disasters, terrorism, wars, embargoes, pandemics, and other catastrophic events;

•energy, market and environmental regulation, legislation, and policies;

•general economic conditions that impact demand and energy consumption; and

•bidding behavior and market bidding rules.

Wholesale power prices may experience significant volatility in our markets which could impact our operations and opportunities for future growth.

The wholesale prices offered for electricity have been volatile in the markets in which we operate due to a variety of factors, including the increased penetration of renewable generation and energy storage resources, low-priced natural gas, demand side management, new regulations, and market rules. The levelized cost of electricity from new solar and wind generation sources has decreased substantially over the past decade as solar panel costs and wind turbine costs have declined, while wind and solar capacity factors have increased. These renewable resources have no fuel costs and very low operational costs, while only operating during certain periods of time (daylight) or weather conditions (higher winds). This, combined with changes in oil, gas, and coal pricing, has led to increasingly volatile electricity markets across our markets. Changing weather conditions can also directly impact electricity supply, demand, and generations sources, leading to price volatility.

Volatility in wholesale prices could have a material adverse impact on the financial performance of our existing generation assets to the extent they currently sell or buy power into the spot market to serve our contracts or will seek to sell power into the spot market once our contracts expire.


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Further, the Chinese market has driven global materials demand and pricing for commodities, many of which are produced in our key electricity markets in South America. Volatility in economic growth in China could result in lower economic growth and lower demand for electricity in our key markets.

We may not have adequate risk mitigation or insurance coverage for liabilities.

Power generation, distribution and transmission involves hazardous activities. We may become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance coverage. Furthermore, through AGIC, AES’ captive insurance company, we take certain insurance risk on our businesses. We maintain an amount of insurance protection that we believe is customary, but there can be no assurance it will be sufficient or effective in light of all circumstances, hazards, or liabilities to which we may be subject. Our insurance does not cover every potential risk associated with our operations. Adequate coverage at reasonable rates is not always obtainable. In particular, the availability of insurance for coal-fired generation assets has decreased as certain insurers have opted to discontinue or limit offering insurance for such assets. Certain insurers have also withdrawn from insuring hydroelectric assets. We cannot provide assurance that insurance coverage will continue to be available in the amounts or on terms similar to our current policies. In addition, insurance may not fully cover the liability or the consequences of any business interruptions such as natural catastrophes, equipment failure, or labor dispute. The occurrence of a significant adverse event not adequately covered by insurance could have a material adverse effect on our business, results or operations, financial condition, and prospects.

We may not be able to enter into long-term contracts that reduce volatility in our results.

Many of our generation plants conduct business under long-term sales and supply contracts, which helps these businesses to manage risks by reducing the volatility associated with power and input costs and providing a stable revenue and cost structure. In these instances, we rely on power sales contracts with one or a limited number of customers for the majority of, and in some cases all of, the relevant plant's output and revenues over the term of the power sales contract. The remaining terms of the power sales contracts of our generation plants range from one to more than 20 years. In many cases, we also limit our exposure to fluctuations in fuel prices by entering into long-term contracts for fuel with a limited number of suppliers. In these instances, the cash flows and results of operations are dependent on the continued ability of customers and suppliers to meet their obligations under the relevant power sales contract or fuel supply contract, respectively. Some of our long-term power sales agreements are at prices above current spot market prices and some of our long-term fuel supply contracts are at prices below current market prices. The loss of significant power sales contracts or fuel supply contracts, or the failure by any of the parties to such contracts that prevents us from fulfilling our obligations thereunder, could adversely impact our strategy by resulting in costs that exceed revenue, which could have a material adverse impact on our business, results of operations and financial condition. In addition, depending on market conditions and regulatory regimes, it may be difficult for us to secure long-term contracts, either where our current contracts are expiring or for new development projects. The inability to enter into long-term contracts could require many of our businesses to purchase inputs at market prices and sell electricity into spot markets, which may not be favorable.

We have sought to reduce counterparty credit risk under our long-term contracts by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from certain sovereign governments of the customer's obligations; however, many of our customers do not have or have not maintained, investment-grade credit ratings. Our generation businesses cannot always obtain government guarantees and if they do, the government may not have an investment grade credit rating. We have also located our plants in different geographic areas in order to mitigate the effects of regional economic downturns; however, there can be no assurance that our efforts will be effective.

Our acquisitions may not perform as expected.

Acquisitions have been a significant part of our growth strategy historically and more recently as we grow our renewables business. Although acquired businesses may have significant operating histories, we may have limited or no history of owning and operating certain of these businesses, and possibly limited or no experience operating in the country or region where these businesses are located. We also may encounter challenges in integrating and realizing the expected benefits of these acquisitions as well as integration or other one-time costs that are greater than expected. Such businesses may not generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; and the rate of return from such businesses may not justify our investment of capital to acquire them. In addition, some of these businesses may have been government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we


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were to acquire any of these types of businesses, there can be no assurance that we will be successful in transitioning them to private ownership or that we will not incur unforeseen obligations or liabilities.

Competition is increasing and could adversely affect us.

The power production markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental or operating experience (including both domestic and international) and financial resources similar to, or greater than, ours. Further, in recent years, the power production industry has been characterized by strong and increasing competition with respect to both obtaining power sales agreements and acquiring existing power generation assets. In certain markets, these factors have caused reductions in prices contained in new power sales agreements and, in many cases, have caused higher acquisition prices for existing assets through competitive bidding practices. The evolution of competitive electricity markets and the development of highly efficient gas-fired power plants and renewables such as wind and solar have also caused, and could continue to cause, price pressure in certain power markets where we sell or intend to sell power. In addition, the introduction of low-cost disruptive technologies or the entry of non-traditional competitors into our sector and markets could adversely affect our ability to compete, which could have a material adverse effect on our businesses, operating results, and financial condition.

Supplier and/or customer concentration may expose us to significant financial credit or performance risks.

We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of some of our facilities. If these suppliers cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price, which could adversely impact the profitability of the affected business and our results of operations, and could result in a breach of agreements with other counterparties, including, without limitation, offtakers or lenders.

The financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers. At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. Counterparties to these agreements may breach or may be unable to perform their obligations, due to bankruptcy, insolvency, financial distress or other factors. Furthermore, in the event of a bankruptcy or similar insolvency-type proceeding, our counterparty can seek to reject our existing PPA under the U.S. Bankruptcy Code or similar bankruptcy laws, including those in Puerto Rico. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, and may have to sell power at market prices. A counterparty's breach of a PPA or other agreement could also result in the breach of other agreements, including the affected businesses' debt agreements. Any failure of a supplier or customer to fulfill its contractual obligations could have a material adverse effect on our financial results.

We may incur significant expenditures to adapt our businesses to technological changes.

Emerging technologies may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, or may result in the obsolescence of certain of our operating assets. Our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services and products that meet customer demands and evolving industry standards. Technological changes that could impact our businesses include:

•technologies that change the utilization of electric generation, transmission and distribution assets, including the expanded cost-effective utilization of distributed generation (e.g., rooftop solar and community solar projects), and energy storage technology;

AES CORP 10-K