AES 10-K & 10-Q changes, risk factors and insider trading

•changes in our operating cost structure, including, but not limited to, increases in costs relating to gas, coal, oiloil, and other fuel; fuel transportation; purchased electricity; operations, maintenancemaintenance, 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, portsports, 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.

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 errorerror, 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.

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, plantplant, 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.

Wind, solar, hydrogen, and energy storage projects are subject to substantial risks. Some of these business lines are dependent upon favorable regulatory incentives to support continued investment, and there is significant uncertainty about the extent to which such favorable regulatory incentives, in particular, those associated with the U.S. Inflation Reduction Act of 2022, will be available in the future. In particular, in the U.S., AES’ renewable energy generation growth strategy dependshas depended in part on federal, statestate, and local government policies and incentives that support the development, financing, ownershipownership, and operation of renewable energy generation projects, including investment tax credits, production tax credits, accelerated depreciation, renewable portfolio standards, feed-in-tariffsfeed-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 them,these policies or incentives, there could be a material adverse impact on AES’ U.S. renewable growth opportunities, including fewer future PPAs or lower prices in future PPAs, decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. 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.

As a result, these types of projects face considerable risk, including that favorable regulatory regimes expireare or arefurther 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.

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, which could result in delaysresources or costfor increasesresources tothat existingservice a resource adequacy need or futurenew 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 negative impacts the development or 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.load,

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,in writing off the costs incurred, expensing related capitalized development costs incurredincurred, and incurring additional losses associated with any related contingent liabilities.

A significant amount of our revenue is generated in developing countriescountries, 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, socialsocial, and political instability in any particular country or region;

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

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

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

•unwillingness of governments, government agencies, courtscourts, 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, administrativeadministrative, and legal systems;

Developing projects in less developed economies also entails greater financing risksrisks, 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 instabilityinstability, and currency devaluations, which may increase the uncertainty of cash flows from these businesses.

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 gasgas, 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.

•seasonality, hydrologyhydrology, and other weather conditions;

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

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

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

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 regulationsregulations, 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.

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, hazardshazards, 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 failurefailure, 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.

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.

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 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.

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 resultsresults, and financial condition.

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

Emerging technologies may also allow new competitors to more effectively compete in our markets or disintermediate the services we provide our customers, including traditional utility and centralized generation services. If we incur significant expenditures in adapting to technological changes, fail to adapt to significant technological changes, fail to obtain access to important new technologies, fail to recover a significant portion of any remaining investment in obsolete assets, or if implemented technology fails to operate as intended, our businesses, operating results and financial condition could be materially adversely affected.

Our business relies on electronic systems and network technologies to operate our generation, transmission and distribution infrastructure. We also use various financial, accounting and other infrastructure systems. Additionally, we store and use customer, employee, and other personal information and other confidential and sensitive information. Our infrastructure may be targeted by nation states, hacktivists, criminals, insiders or terrorist groups. In particular, there has been an increased focus on the U.S. energy grid believed to be related to thevarious Russia/Ukrainegeopolitical conflict.conflicts. Such an attack, by hacking, malware or other means, may interrupt our operations, cause property damage, affect our ability to control our infrastructure assets, cause the release of sensitive customer information or limit communications with third parties. Any loss or corruption of confidential or proprietary data through a breach of our systems or certain of our third partythird-party vendor systems may:

•impact our operations, revenue, strategic objectives, or customer and vendor relationships;

We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. To date, cyber breaches have not had a material impact on our operations or financial results. We continue to assess potential threats and vulnerabilities and make investments to address them, including global monitoring of networks and systems, identifying and implementing new technology, improving user awareness through employee security training, and updating our security policies as well as those for third-party providers. We cannot guarantee the extent to which our security measures will prevent future cyber-attacks and security breaches or that our insurance coverage will adequately cover any losses we may experience. Further, we do not control certain of our joint ventures or our equity method investments and cannot guarantee that their efforts will be effective.

Regional or global outbreaks of infectious or contagious diseases, such as occurred during the COVID-19 pandemic, could have material and adverse effects on our results of operations, financial conditioncondition, and cash flows due to, among other factors:

•negative impacts on the health of our essential personnel and on our operations as a result of implementing stay-at-home, quarantine, curfewcurfew, and other social distancing measures;

•delays in achieving our financial goals, strategystrategy, and digital transformation;

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

In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad geographic regions in which our hydroelectric generation facilities are located. Changes in temperature, precipitation and snow packsnowpack conditions also could affect the amount and timing of hydroelectric generation. To the extent that hydrological conditions result in droughts or other conditions negatively affect our hydroelectric generation business, such as has happened in Panama in 2019, Brazil in 20212019 and Colombia in 2024, our results of operations can be materially adversely affected. Additionally, our contracts in certain markets where hydroelectric facilities are prevalent may require us to purchase power in the spot markets when our facilities are unable to operate at anticipated levels and the price of such spot power may increase substantially in times of low hydrology.

Depending on the nature and location of the facilities and infrastructure affected, any such incident also could cause catastrophic fires; releases of natural gas, natural gas odorant, or other greenhouse gases; explosions, spills or other significant damage to natural resources or property belonging to third parties; personal injuries, health impactsimpacts, or fatalities; or present a nuisance to impacted communities. Such incidents may also impact our business partners, supply chainschains, and transportation, which could negatively impact construction projects and our ability to provide electricity and natural gas to our customers.

A disruption or failure of electric generation, transmission or distribution systems or natural gas production, transmission, storagestorage, or distribution systems in the event of a hurricane, tornadotornado, or other severe weather event, or otherwise, could prevent us from operating our business in the normal course and could result in any of the adverse consequences described above. At our businesses where cost recovery is available, recovery of costs to restore service and repair damaged facilities is or may be subject to regulatory approval, and any determination by the regulator not to permit timely and full recovery of the costs incurred. Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation, and prospects.

We have invested in some joint ventures in which our subsidiaries share operational, management, investmentinvestment, and/or other control rights with our joint venture partners. In many cases, we may exert influence over the joint venture pursuant to a management contract, by holding positions on the board of the joint venture company or on management committees and/or through certain limited governance rights, such as rights to veto significant actions. However, we do not always have this type of influence over the project or businessbusiness, and we may be dependent on our joint venture partners or the management team of the joint venture to operate, manage, investinvest, or otherwise control such projects or businesses. Our joint venture partners or the management team of our joint ventures may not have the level of experience, technical expertise, human resources, managementmanagement, and other attributes necessary to operate these projects or businesses optimally, and they may not share our business priorities. In some joint venture agreements in which we do have majority control of the voting securities, we have entered into shareholder agreements granting minority rights to the other shareholders.

Further, we have a significant equity method investment in Fluence. As a publicly listed company, Fluence is governed by its own Board of Directors, whose members have fiduciary duties to the Fluence shareholders. While we have certain rights to appoint representatives to the Fluence Board of Directors, the interests of the Fluence shareholders, as represented by the Fluence Board of Directors, may not align with our interests or the interests of our securityholders. AsIn ofrecent December 31, 2024,years, Fluence continueshas to report thatreported a material weakness in its internal control over revenue recognition hasthat notwas yetremediated beenas remediated.of SuchDecember 31, 2024. If there is a material weakness in the future, that can impact the reliability of the Fluence financial information that we may include as part of our financial information.

In addition, we are generally dependent on the management team of our equity method investments to operate and control such projects or businesses. While we may exert influence pursuant to having positions on the boards of such investments and/or through certain limited governance rights, such as rights to veto significant actions, we do not always have this type of influenceinfluence, and the scope and impact of such influence may be limited. The management teams of our equity method investments may not have the level of experience, technical expertise, human resources, managementmanagement, and other attributes necessary to operate these projects or businesses optimally, and they may not share our business priorities, which could have a material adverse effect on the value of such investments as well as our growth, business, financial condition, results of operations and prospects.

We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel requirements, and other commodities to lower our financial exposure related to commodity price fluctuations. As part of this strategy, we routinely utilize fixed price or indexed forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. We also enter into contracts which help us manage our interest rate exposure. However, we may not cover the entire exposure of our assets or positions to market price or interest rate volatility, and the coverage will vary over time. Furthermore, the risk management practices we have in place may not always perform as planned. In particular, if prices of commodities or interest rates significantly deviate from historical prices or interest rates or if the price or interest rate volatility or distribution of these changes deviates from historical norms, our risk management practices may not protect us from significant losses. As a result, fluctuating commodity prices or interest rates may negatively impact our financial results to the extent we have unhedged or inadequately hedged positions. In addition, certain types of economic hedging activities may not qualify for hedge accounting under U.S. GAAP, resulting in increased volatility in our net income. The Company may also suffer losses associated with "basis risk," which is the difference in performance between the hedge instrument and the underlying exposure (usually the pricing node of the generation facility). Furthermore, there is a risk that the current counterparties to these arrangements may fail or are unable to perform part or all of their obligations under these arrangements, while we seek to protect against that by utilizing strong credit requirements and exchange trades, these protections may not fully cover the exposure in the event of a counterparty default. For our businesses with PPA pricing that does not completely pass through our fuel costs, the businesses attempt to manage the exposure through flexible fuel purchasing and timing of entry and terms of our fuel supply agreements; however, these risk management efforts may not be successful and the resulting commodity exposure could have a material impact on these businesses and/or our results of operations.

We have 27 defined benefit plans, five at U.S. subsidiaries and the remaining plans at foreign subsidiaries, which cover substantially all of the employees at these subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be incorrect, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. We periodically evaluate the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. Downturns in the debt and/or equity markets, or the inaccuracy of any of our significant assumptions underlying the estimates of our subsidiaries' pension plan obligations, could result in a material increase in pension expense and future funding requirements. Our subsidiaries that participate in these plans are responsible for satisfying the funding requirements required by law in their respective jurisdictions for any shortfall of pension plan assets as compared to pension obligations under the pension plan, which may necessitate additional cash contributions to the pension plans that could adversely affect our and our subsidiaries' liquidity. See Item 7.—Management's Discussion and Analysis—Critical Accounting Policies and Estimates—Pension and Other Postretirement Plans and Note 16—Benefit Plans included in Item 8.—Financial Statements and Supplementary Data.

Long-lived assets are initially recorded at cost or fair value, are depreciated over their estimated useful lives, and are evaluated for impairment only when impairment indicators are present, such as deterioration in general economic conditions or our operating or regulatory environment; increased competitive environment; lower forecasted revenue; increase in fuel costs, particularly costs that we are unable to pass through to customers; increase in environmental compliance costs; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; developments in our strategy; divestiture of a significant component of our business; or adverse actions or assessments by a regulator. Any impairment of long-long-lived assets could have a material adverse effect on our business, financial condition, results of operations, and prospects.

•changes in the determination, definitiondefinition, or classification of costs to be included as reimbursable or pass-through costs to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;

Furthermore, in many countries where we conduct business, the regulatory environment is constantly changing and it may be difficult to predict the impact of the regulations on our businesses. The impacts described above could also result from our efforts to comply with European Market Infrastructure Regulation, which includes regulations related to the trading, reporting and clearing of derivatives and similar regulations may be passed in other jurisdictions where we conduct business. Any of the above events may result in lower operating margins and financial results for the affected businesses.

For discussion of the Company's year ended December 31, 20232024 compared to the year ended December 31, 2022,2023, refer to Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in our 20232024 Form 10-K filed with the SEC on FebruaryMarch 26,11, 2024.2025.

In 2024,2025, AES delivered on its strategic and financial objectives. We completed construction or the acquisition of 3.03.2 GW of renewables and energy storage, construction of a 670 MW combined cycle gas plant, and signed long-term PPAs for an additional 4.44.0 GW of new renewable energy. See Overview of our Strategy included in Item 1.—Business of this Form 10-K for further information.

Adjusted EPS,EBITDA, a non-GAAP measure, increased $0.38$232 million, from $1.76$2,639 million to $2.14,$2,871 million, mainly driven by higher contributions from renewablesnew projects placedand inbetter servicehydrology in the currentRenewables year, a lower adjusted tax rate,SBU, and higher contributionsretail frommargin at the Utilities SBU; partially offset by lowerhigher contributionsprior year revenues from the monetization of the Warrior Run coal plant PPA in the Energy Infrastructure SBU.SBU, the sale of AES Brasil in the prior year, and the impact of the AES Ohio and AGIC sell-downs.

Components of Revenue, Cost of SalesSales, and Operating Margin — Revenue includes revenue earned from the sale of energy from our utilities and the production and sale of energy from our generation plants, which are classified as regulated and non-regulated, respectively, on the Consolidated Statements of Operations. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.

Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, operations and maintenanceO&M costs, depreciation and amortization expenses, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

Consolidated Revenue — Revenue decreased $390$45 million, or 3%,million in 20242025 compared to 2023,2024, driven by:

•$75$50 million at NewCorporate, EnergyOther Technologiesand Eliminations mainly driven by thehigher saleeliminations of theinter-segment Fallbrook project in March 2023.revenue.

•$113$514 million at Utilities mainly driven by a $252$422 million increase in transmission, distribution, rider, and riderwholesale revenues mainly due to higher rates, and $57$93 million due to higher net retail demand mainly driven by favorable weather; partially offset by $181 million of lower Fuel Adjustment Charge rider revenue.and

These unfavorable impacts were partially offset by an increase of $110•$92 million at Utilities primarilymainly driven by $83 million due to higher transmission and rider revenues, $76$191 million due to higher retail rates as a result of the AES Indiana 2024 Base Rate Order,Order and $72AES millionOhio due2024 toDRC Settlement, higher transmission and rider revenues, and higher demand primarilydue fromto the impact of weather; partially offset by $57a $46 million higherincrease in depreciation expense from additional assets placed in service, thea prior year $29$33 million deferralincrease in fixed cost mainly driven by higher property taxes, and a $14 million impact of powerplanned purchase costs associated with the approval of ESP 4,outages; and $25 million higher expected credit losses due to the one-time implementation of customer billing system upgrades.

General and administrative expenses increaseddecreased $33$47 million, or 13%,16%, to $241 million in 2025 compared to $288 million in 2024 compared to $255 million in 2023,2024, primarily due to increaseda $34 million decrease in business development costs, higherdriven peopleby the Company's restructuring program, $18 million lower IT costs, higherand $8 million lower professional fees, andpartially higheroffset ITby costs.$14 million of one-time costs due to restructuring.

Loss on extinguishment of debt decreasedincreased $46$9 million, or 53%, to $26 million in 2025, compared to $17 million in 2024, compared to $63 million in 2023.2024. This decreaseincrease was primarily duedriven by a $9 million loss related to priora yearrevolver lossesamendment and prepayment of $47debt at AES Clean Energy, a $7 million and $10 millionloss due to prepaymentsprepayment of debt at AESJordan AndesSolar, and AESa Hispanola$5 Holdingsmillion BV,loss respectively,due to prepayment of senior notes at Mercury Chile; partially offset by a currentprior year loss of $10 million due to a prepayment at AES Andes.

Other income increaseddecreased $67$89 million, or 75%,57%, to $67 million in 2025, compared to $156 million in 2024, compared to $89 million in 20232024 primarily due to the prior year recognition of a $20 million bargain purchase gain recognized on the Madison and Birdseye acquisition for $20 million,acquisition, a $17prior millionyear increase in gains on remeasurementgain of contingent consideration primarily on projects acquired at AES Clean Energy, a $14 million gain corresponding to the step acquisition of Felix, and ana prior year indexation adjustment of Stabilization Fund receivables at AES Andes of $12 million.million, as well as a $10 million decrease in insurance proceeds and a $7 million decrease in AFUDC at our U.S. utilities in the current year. This was partially offset by a $10 million gain at AES Andes in the current year corresponding to the write-off of contingent consideration for a renewables development project determined to be no longer viable.

Other expense increased $76$283 million,million orto 77%,$458 million in 2025, compared to $175 million in 2024, compared to $99 million in 20232024 primarily driven by $52$159 million higher losses on commencement of sales-type leases at AES Clean Energy and AES Renewable Holdings, a $43$74 million increase in losses on remeasurement of contingent consideration primarily on projects acquired at AES Clean Energy, and a $48 million current year loss on remeasurement of our investment in 5B, accounted for using the measurement alternative; partially offset by a $20 million loss recognized in the prior year related to legal expenses and other direct costs associated with the troubled debt restructuring at Puerto Rico. This was partially offset by a $36 million decrease in loss on sale and disposal of assets, mainly driven by prior year impairments of inventory due to the planned early plant closures at Ventanas 2, Norgener, and Warrior Run.

Gain (loss) on disposal and sale of business interests

Gain on disposal and sale of business increaseddecreased $217$293 million to $58 million in 2025, compared to $351 million in 2024,2024. comparedThis decrease was primarily due to $134the millionprior in 2023. This increase was driven by theyear gain on sale of AES Brasil of $312 million and a $52 million gain corresponding toin the prior year on dilution of AES' ownership interest in Uplight as a result of the AutoGrid acquisition;acquisition. This was partially offset by a $136$70 million gain on salethe sell-down of sharesDominican ofRepublic Fluence, our equity method investment, in 2023, and the $10 million loss on the selldown of Amman East and IPP4 in Jordan,Renewables, which is now accounted for as an equity method investment.

(21) Includes losses of $26 million and gains of $137 million and losses of $28 million on foreign currency derivative contracts for the years ended December 31, 20242025 and 2023,2024, respectively.

Income tax benefit (expense)

Income tax benefit was $181 million in 2025 compared to income tax expense wasof $59 million in 2024 compared to $261 million in 2023.2024. The Company's effective tax rates were 7%(241)% and 251%7% for the years ended December 31, 20242025 and 2023,2024, respectively.

The 2025 effective tax rate was impacted by the current year benefits associated with ITCs and the reclassification of the Mong Duong asset group as held and used from held-for-sale, partially offset by the impacts of allocations of losses to tax equity investors on renewables projects. The 2024 effective tax rate was impacted by the currentprior year benefits associated with ITCs and the restructuring of a foreign holding company. These drivers were partially offset by the impacts of allocations of losses to tax equity investors on renewables projects. See Note 23—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the Mong Duong reclassification.

The Merger is currently expected to close in late 2026 or early 2027, subject to satisfaction or waiver (to the extent permitted by law) of all closing conditions. The approval of the shareholders was received on June 26, 2026. However, we may be unable to obtain and satisfy, or experience delays in obtaining and satisfying, required regulatory approvals and other closing conditions. In addition, both we and the Parent may terminate the Merger Agreement for reasons specified therein.

•We have incurred, and will continue to incur, significant costs, expenses, and fees for professional services and other transaction costs in connection with the Merger. Many of the fees and costs will be payable by us even if the Merger is not completed. In addition, we may be required to pay a termination fee of approximately $321 million to Parent if the Merger Agreement is terminated by us for certain specified reasons; and 75 | The AES Corporation | March 31, 2026 Form 10-Q

WeThe mayCompany beand theits targetdirectors ofhave been named in securities class action and derivative lawsuits arising out of the proposed Merger, which could result in substantial costs and may delay or prevent the proposed Merger or otherwise negatively affect our business and operations.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into a merger agreement. EvenTo ifdate, two (2) complaints have been filed as individual actions in connection with the Merger by purported stockholders of the Company against the Company and the individual members of the Company’s Board of Directors. In addition, the Company has received sixteen (16) demand letters from law firms claiming to represent purported Company stockholders, which also generally allege disclosure deficiencies in the Preliminary Proxy Statement filed on May 4, 2026 (the “Preliminary Proxy Statement”) and/or the Definitive Proxy Statement filed on May 15, 2026 (the “Definitive Proxy Statement”), respectively, two (2) stockholder books and records demands, and one stockholder demand for an appraisal of the stockholder’s alleged shares. Although these lawsuits and demands are without merit, defending against these claims can result in substantial costs to the parties to the mergerMerger agreementAgreement and divertdiverts management time and resources. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting the completion of a merger, that injunction may delay or prevent such merger from being completed. If the Merger is not consummated for any reason, litigation could be filed in connection with the failure to consummate the Merger.

•the risk that the conditions to the completion of the Transaction, including obtaining required Stockholder and regulatory approvals,Transaction are not satisfied in a timely manner or at all;

Adjusted EBITDA, a non-GAAP measure, increased $236$217 million, from $591$681 million to $827$898 million, driven by higher contributions from development services in the U.S. and renewables projects placed in service, higher 38 | The AES Corporation | March 31, 2026 Form 10-Q contributions from the Energy Infrastructure SBU primarily due toU.S., higher energy and capacity sales and prices in the spot market andmarket, the increase in ownership of Cochrane, and higher retail margin primarily at AES Ohio and AES Indiana; partially offset by lower contract sales volume mainly due to the impactexpiration of the AESMaritza OhioPPA andin AGIC selldowns.Bulgaria.

3948 | The AES Corporation | MarchJune 31,30, 2026 Form 10-Q

4051 | The AES Corporation | MarchJune 31,30, 2026 Form 10-Q

Consolidated Revenue — Revenue increased $254$567 million, or 9%,20%, for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, driven by:

•$154$295 million at Renewables mainly driven by a $76 million favorable impact from energy derivatives in the U.S., $67 million higher spot sales and prices in Colombia driven by El Niño, $63 million due to development services in the U.S., $37$53 million due to new projects placed in service mainly in the U.S,U.S. $19and Chile, $27 million positive impact due to the appreciation of the Colombian peso, and $21 million higher revenues under our retail supply agreements,agreements; apartially $17offset by $13 million favorable impact from changes in mark-to-market of energy derivatives in the U.S., and $16 million due to higherlower contracted and spot sales in Chile;

These favorable impacts were partially offset by a decrease of $64•$190 million at Energy Infrastructure mainly driven by $146 million lower contracted sales volume and prices, and $8$188 million of priorhigher yearenergy and capacity sales and prices in the spot market in Argentina, $25 million of higher spot sales in Mexico driven by the expiration of a PPA, $24 million of higher LNG sales, and $23 million of net derivative gains as part of our commercial hedging strategy; partially offset by $56$72 million oflower higher energy and capacitycontract sales andvolume pricesmainly driven by the expiration of the Maritza PPA in the spot market, and $34 million of higher LNG sales.Bulgaria;

Consolidated Operating MarginRevenue — Operating marginRevenue increased $199$821 million, or 45%,14%, for the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025, driven by:

•$90$449 million at Renewables mainly driven by $55$126 million due to development services in the U.S., $29 million of higher contracted margin in Chile and Colombia, a $17$93 million favorable impact from changes in mark-to-market of energy derivatives in the U.S., and $16$90 million due to one-timenew restructuringprojects costsplaced incurredin service in the priorU.S. year;and Chile, $48 million higher spot sales and prices in Colombia, mainly driven by El Niño and partially offset by a $17 million impact from lower spot prices in Colombiathe first quarter, $40 million positive impact due to the appreciation of the Colombian peso, and $40 million higher revenues under our retail supply agreements;

•$78$191 million at Utilities mainly driven by $38$92 million due to higher transmission and rider revenues, $84 million due to higher retail rates as a result of AES Ohio’s 2024 DRC Settlement in November 2025, and a $37$17 million increase duein towholesale revenues at AES Indiana driven by higher transmissionload requirements and riderincreased 41capacity |from Thenew AESrenewables Corporationprojects |placed Marchin 31, 2026 Form 10-Q revenuesservice;

•$12$126 million at Energy Infrastructure mainly driven by $29$201 million higher energy and capacity sales and prices in the spot market,market mainly in Argentina, $61 million of higher spot sales in Mexico driven by the expiration of a PPA, $61 million higher LNG sales, and $14 million lowerof fixedprior costs mainly due to the 2025 restructuring, $4 million due to higheryear net unrealized derivative gains,losses $3as millionpart drivenof byour highercommercial LNGhedging salesstrategy; partially offset by $24$207 million higherlower depreciationcontract atsales Maritzavolume due to the useful life reassessment in the prior year, and $13 millionmainly driven by lowerthe contractedexpiration capacityof the Maritza PPA in Bulgaria; and contract prices.

General and administrative expenses decreasedincreased $22$13 million, or 29%,27%, to $55$62 million for the three months ended MarchJune 31,30, 2026, compared to $77$49 million for the three months ended MarchJune 31,30, 2025, primarily due to a $20 million decrease in business development costs, $8 million of one-time costs, and $4 million lower people costs, all driven by the Company's restructuring program in February 2025; partially offset by $11 million of costs related to the Merger.Merger and a $5 million increase in business development costs, partially offset by $3 million lower professional fees.

Interest expense increased $11$16 million, or 3%,5%, to $353$368 million for the three months ended MarchJune 31,30, 2026, compared to $342$352 million for the three months ended MarchJune 31,30, 2025. This increase is primarily due to higher debt balances and lower capitalized interest at the Renewables SBU due to fewer projects under construction, and higher interest expense at the Parent Company due to a higher weighted average interest rate and debt balance as well as the impact of a prior year realized gain on a de-designated interest rate swap, and lower capitalized interest at the Renewables SBU due to fewer projects under construction; partially offset by lower debt balances at the Energy Infrastructure SBU and Renewables SBU.

Asset impairmentInterest expense decreasedincreased $37$27 million, or 76%,4%, to $12$721 million for the threesix months ended MarchJune 31,30, 2026, compared to $49$694 million for the threesix months ended MarchJune 31,30, 2025. TheThis decreaseincrease wasis primarily due to lowerhigher impairmentinterest expense of $25 million at AESthe CleanParent Energy DevelopmentCompany due to thea write-offhigher ofweighted projectaverage developmentinterest intangiblesrate and capitalizeddebt developmentbalance costsas forwell projectsas thatthe wereimpact determined to be no longer viable andof a prior year impairmentrealized ofgain $17on milliona de-designated interest rate swap, and lower capitalized interest at Mong Duong associated with the held-for-saleRenewables classificationSBU due to thefewer carryingprojects amountunder ofconstruction; partially offset by lower debt balances at the MongEnergy DuongInfrastructure disposal group exceeding the expected sales proceeds.SBU.

Foreign currency transaction gains (losses)

___________________________________________ (1)Includes losses of $9$36 million and $3$12 million on foreign currency derivative contracts for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and losses of $45 million and $14 million on foreign currency derivative contracts for the six months ended June 30, 2026 and 2025, respectively.

The Company recognized net foreign currency transaction losses of $10$52 million for the three months ended MarchJune 31,30, 2025,2026, primarily driven by unrealized foreign currency derivative losses in Argentina, unrealized losses due to the depreciation of the Argentine peso, and unrealized losses in Chile due to the appreciation of the Chilean peso.peso and the appreciation of the Colombian peso, which negatively impacted foreign currency forwards.