AES CORP

During 2024 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate,

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or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation, and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.—Businessand Item 1A.—Risk Factors of our 2023 Form 10-K.

Operational

Trade Restrictions and Supply Chain— On March 29, 2022, the U.S. Department of Commerce (“Commerce”) announced the initiation of an investigation into whether imports into the U.S. of solar cells and panels imported from Cambodia, Malaysia, Thailand, and Vietnam (“Southeast Asia”) are circumventing antidumping and countervailing duty (“AD/CVD”) orders on solar cells and panels from China. This investigation resulted in significant systemic disruptions to the import of solar cells and panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any circumvention duties on imported solar cells and panels from Southeast Asia that result from this investigation for a 24-month period ending June 6, 2024. Suppliers resumed importing cells and panels from Southeast Asia into the U.S. pursuant to a Commerce certification regime implementing the Proclamation.

On December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four Southeast Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to several but not all of these companies. Additionally, Commerce issued a preliminary determination that circumvention would not be deemed to occur for any solar cells and panels imported from the four countries if the wafers comprising the cells and panels were manufactured outside of China or if no more than two out of six specifically identified panel components were produced in China. On August 18, 2023, Commerce issued its final determinations and affirmed its preliminary findings in most respects. Commerce found that three of the specific companies it investigated were not circumventing. Several parties have challenged Commerce’s circumvention final determinations before the U.S. Court of International Trade (“CIT”), arguing that the determinations were not supported by substantial evidence or otherwise rendered in accordance with governing law.

On December 29, 2023, Auxin Solar and Concept Clean Energy filed a lawsuit before CIT, challenging certain aspects of the final rule promulgated by Commerce to implement the Proclamation. The lawsuit specifically challenges Commerce’s decisions not to suspend the final disposition of certain entries of imported solar cells and panels from Southeast Asia made prior to June 6, 2024, and not to collect AD/CVD deposits with respect to those entries. Certain U.S. developers, associations, and foreign solar producers have intervened in the case to support Commerce’s final rule. The CIT denied motions to dismiss filed by the U.S. Department of Justice, and the defendant-intervenors, and on July 22, 2024, plaintiffs filed their opening brief on the merits.

On April 24, 2024, new Commerce regulations with respect to the administration of AD/CVD cases went into effect, including regulations pertaining to transnational subsidization and particular market situations. On the same day, several companies filed a petition requesting that Commerce initiate an investigation into whether new AD/CVD duties should be imposed on cells and modules imported from Thailand, Cambodia, Malaysia, and Vietnam. These petitions cover exports of cells and panels from Southeast Asia that are not otherwise subject to the Commerce circumvention determinations. On May 14, 2024, Commerce initiated new AD/CVD investigations with respect to all four countries, and the U.S. International Trade Commission (the “ITC”) preliminarily voted to continue its investigations on June 7, 2024. Commerce is scheduled to announce its preliminary determinations and duty rates in these investigations in the fall of 2024. The ITC will conduct its final injury investigation with respect to these exports from Southeast Asia in the first half of 2024. If the Commerce and ITC investigations result in Commerce issuing AD/CVD orders, the orders are likely to be imposed in the second or third quarter of 2025.

Separately, the United States maintains a global tariff (currently 14.25% ad valorem) on solar cells and modules pursuant to the Section 201 Safeguard Action on crystalline silicon photovoltaic products, which became effective in February 2018. On June 21, 2024, President Biden issued Proclamation 10779, revoking the exclusion of bifacial panels from safeguard relief previously proclaimed in Proclamation 10339, and reinstating bifacial panels under the Section 201 Safeguard Action, subject to certain qualifications.

Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China and may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While this has impacted the U.S. market, AES has managed this issue without significant impact to our projects. Further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements or to continue to supply cells or panels into the U.S. market on terms that we deem satisfactory.

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The impact of new Commerce investigations or any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the solar panel supply chain and their effect on AES’ U.S. solar project development and construction activities remain uncertain. AES will continue to monitor developments and take prudent steps towards maintaining a robust supply chain for our renewables projects. To that end, we have contracted and secured all of the necessary solar panels for our projects in our backlog expected to come online through 2026. We expect to have all the 2024 panels and the majority of the 2025 and 2026 panels on site or in storage by September.

Additionally, as part of our supply chain strategy, we are well advanced in securing domestically manufactured modules to support our US solar growth from 2026 to 2028, with a contractual option to extend deliveries to 2030.

Operational Sensitivity to Dry Hydrological Conditions— Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Dry hydrological conditions in Panama, Brazil, Colombia, and Chile can present challenges for our businesses in these markets. Low inflows can result in low reservoir levels, reduced generation output, and subsequently possible increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have an adverse impact on AES. As mitigation, AES has invested in thermal, wind, and solar generation assets, which have a complementary profile to hydroelectric plants. These plants are expected to have increased generation in low hydrology scenarios, offsetting possible impacts described from hydro assets.

According to the National Oceanic and Atmospheric Administration ("NOAA"), neutral conditions are observed and forecasted through the beginning of Q3 2024. A transition to La Niña is expected by mid / late Q3 2024.

In Panama, La Niña phenomenon in contrast to El Niño typically means wetter conditions than average, although local system impacts may vary due to other factors. Higher hydrology may result in energy surpluses after covering the contracted hydro positions, available to be sold in the spot market after fulfilling contract obligations.

In Colombia, La Niña is typically characterized by more rainfall, possibly leading to a decrease in spot prices. However, during La Niña, impacts vary and the basin where Chivor is located may experience drier conditions than the system.

In Brazil, La Niña results in more rainfall in the north, drier conditions in the south, and milder temperatures in the central region. Current system reservoir levels remain high, supporting lower spot market prices. However, inflows lower than expected may cause spot and future prices to rise. Lower prices limit external thermal generation which, if dispatched, could impact demand for the AES hydro generation.

In Chile, the primary driver for AES’ hydro assets is snowpack volumes. La Niña in Chile tends to divert the frontal systems to the south of Chile, reducing rainfall in the central area, possibly reducing the snowpack formation. Lower snowpack, together with reduced rainfall in the system, could increase both spot prices and energy purchase volumes required to meet contracted positions.

The exact behavior pattern and strength of La Niña is unknown and therefore the impacts could vary from those described above, and may include impacts to our businesses beyond hydrology, including with respect to power generation from other renewable sources of energy and demand. Even if rainfall and water inflows return to historical averages, in some cases market prices and generation above or below the average could persist until reservoir levels are fully recovered. Further, investments made in thermal, wind, and solar power generation may benefit from uncontracted spot sales at higher market prices. Impacts may be material to our results of operations.

Macroeconomic and Political

During the past few years, some countries where our subsidiaries conduct business have experienced macroeconomic and political changes. In the event these trends continue, there could be an adverse impact on our businesses.

Inflation Reduction Act and U.S. Renewable Energy Tax Credits — The U.S. Inflation Reduction Act of 2022 (the “IRA”) includes provisions that benefit the U.S. clean energy industry, including increases, extensions, direct transfers, and/or new tax credits for onshore and offshore wind, solar, storage, and hydrogen projects. The IRA extends solar investment tax credits ("ITCs") and provides higher credits for projects that satisfy wage and apprenticeship requirements, which benefit our U.S. renewables business.

Our U.S. renewables business has a 51 GW pipeline that we intend to utilize to continue to grow our business, and these changes in tax policy are supportive of this strategy. We account for U.S. renewables projects according to U.S. GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method.

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This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the investment tax credit begins in the quarter the project is placed in service. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy.

The IRA also allows us to directly transfer investment tax credits to unrelated tax credit buyers. We account for the transfer proceeds as tax benefit throughout the year the renewables project is placed in service.

In 2023, we realized $611 million of earnings from tax attributes, comprised of $593 million from the Renewables SBU and $18 million from the Utilities SBU. In 2024, we expect an increase in tax attributes earned by our U.S. renewables business in line with the growth in that business. Based on construction schedules, a significant portion of these earnings will be realized in the fourth quarter. For the six months ended June 30, 2024, we recognized $419 million in tax attributes.

The implementation of the IRA requires substantial guidance from the U.S. Department of Treasury and other government agencies. While some of that guidance remains pending, there will be uncertainty with respect to the implementation of certain provisions of the IRA.

Argentina — President Javier Milei was elected on December 10, 2023 and has instituted a series of reforms impacting the power sector.

On July 8, 2024, the Argentine government enacted Law 27,742 or Ley Bases, translated in English as Law of Bases and Starting Points for the Freedom of the Argentine People. Ley Bases declares a public emergency in administrative, economic, financial, and energy matters for a term of one year, grants delegated powers to the President, and contains a broad reform of the State in order to deregulate the economy, including measures such as labor reform, the implementation of the Incentive Regime for Large Investments, and the modification of several tax measures. The law also opens avenues for privatization of state-owned energy companies.

In addition, the Ministry of Energy published Resolution 150/2024 on July 10, 2024 that repeals certain regulations from previous years that imply excessive involvement of the National State and CAMMESA in the operation and functioning of the wholesale electricity market.

These changes may have a profound impact on the sector, influencing our operations and financial results. It is not yet possible to predict the impact of these regulations in our consolidated results of operations, cash flows, and financial condition.

Global Tax— The macroeconomic and political environments in the U.S. and in some countries where our subsidiaries conduct business have changed in recent years. This could result in significant impacts to future tax law. In the U.S., the IRA includes a 15% corporate alternative minimum tax based on adjusted financial statement income. Additional guidance is expected to be issued in 2024.

During 2023, the Netherlands, Bulgaria, and Vietnam adopted legislation to implement Pillar 2 effective as of January 1, 2024. We will continue to monitor the issuance of draft legislation in other non-EU countries where the Company operates that are considering Pillar 2 amendments and new interpretive guidance. The impact to the Company during 2024 is not expected to be material.

Inflation— In the markets in which we operate, there have been higher rates of inflation recently. While most of our contracts in our international businesses that are denominated in a currency other than the U.S. dollar are indexed to inflation, in general, our U.S.-based generation contracts are not indexed to inflation. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may also increase the costs of some of our development projects that could negatively impact their competitiveness. Our utility businesses do allow for recovering of operations and maintenance costs through the regulatory process, which may have timing impacts on recovery.

Interest Rates— In the U.S. and other markets in which we operate, there has been a rise in interest rates since 2021, and interest rates are expected to remain volatile in the near term.

As discussed in Item 3—Quantitative and Qualitative Disclosures about Market Risk, although most of our existing corporate and subsidiary debt is at fixed rates, an increase in interest rates can have several impacts on our business. For any existing debt under floating rate structures and any future debt refinancings, rising interest rates will increase future financing costs. In most cases in which we have floating rate debt, our revenues serving this debt are indexed to inflation, which helps mitigate the impact of rising rates. For future debt refinancings, AES actively manages a hedging program to reduce uncertainty and exposure to future interest rates. For new business, higher interest rates increase the financing costs for new projects under development and which have not yet secured financing.

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AES typically seeks to incorporate expected financing costs into our new PPA pricing such that we maintain our target investment returns, but higher financing costs may negatively impact our returns or the competitiveness of some of our development projects. Additionally, we typically seek to enter into interest rate hedges shortly after signing PPAs to mitigate the risk of rising interest rates prior to securing long-term financing.

Puerto Rico — As discussed in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties of the 2023 Form 10-K, our subsidiaries in Puerto Rico have long-term PPAs with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was enacted to create a structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). PROMESA also expedites the approval of key energy projects and other critical projects in Puerto Rico.

PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Ilumina’s non-recourse debt of $23 million continues to be in technical default and is classified as current as of June 30, 2024.

In 2022, a mediation commenced to resolve the PREPA Title III case. The confirmation trial ended in March 2024 and the decision is pending.

Considering the information available as of the filing date, management believes the carrying amount of our long-lived assets in Puerto Rico of $203 million is recoverable as of June 30, 2024.

Decarbonization Initiatives

Our strategy involves shifting towards clean energy platforms, including renewable energy, energy storage, LNG, and modernized grids. It is designed to position us for continued growth while reducing our carbon intensity and to be in support of our mission of accelerating the future of energy, together. We have made significant progress on our exit of coal generation, and we intend to exit the substantial majority of our remaining coal facilities by year-end 2025 and intend to exit all of the coal facilities by year-end 2027, subject to necessary approvals.

In addition, initiatives have been announced by regulators, including in Chile, Puerto Rico, Bulgaria, and offtakers in recent years, with the intention of reducing GHG emissions generated by the energy industry. In parallel, the shift towards renewables has caused certain customers to migrate to other low-carbon energy solutions and this trend may continue.

Although we cannot currently estimate the financial impact of these decarbonization initiatives, new legislative or regulatory programs further restricting carbon emissions or other initiatives to voluntarily exit coal generation could require material capital expenditures, result in a reduction of the estimated useful life of certain coal facilities, or have other material adverse effects on our financial results.

For further information about the risks associated with decarbonization initiatives, see Item 1A.—Risk Factors—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 included in the 2023 Form 10-K.

Regulatory

El Salvador— On July 17, 2024, the Government of El Salvador passed various changes to the electricity law impacting, among other things, tariff reset timing and the treatment of bi-lateral contracts. These changes are pending clarification once published in the electricity regulation. Pending completion of that process, the impact of these changes is unclear, but they may be adverse to the Company’s financial condition and results.

AES Maritza PPA Review— DG Comp is conducting a preliminary review of whether AES Maritza’s PPA with NEK is compliant with the European Union's State Aid rules. No formal investigation has been launched by DG Comp to date. AES Maritza has previously engaged in discussions with the DG Comp case team and the Government of Bulgaria (“GoB”) to attempt to reach a negotiated resolution of the DG Comp’s review (“PPA Discussions”). There are no active PPA Discussions at present but those discussions could resume at any time. The

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PPA continues to remain in place. However, there can be no assurance that, in the context of DG Comp’s preliminary review or any future PPA Discussions, the other parties will not seek a prompt termination of the PPA.

We do not believe termination of the PPA is justified. Nevertheless, the PPA Discussions involved a range of potential outcomes, including but not limited to the termination of the PPA and payment of some level of compensation to AES Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict whether and when the PPA Discussions might resume or the outcome of any such discussions. Nor can we predict how DG Comp might resolve its review if the PPA Discussions do not resume or if any such discussions fail to result in an agreement concerning the agency's review. AES Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurance that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of operations, and cash flows. As of June 30, 2024, the carrying value of our long-lived assets at Maritza is $326 million.

AES Indiana DSM Plan Petition — On May 31, 2024, AES Indiana filed a petition with the IURC asking for approval of a two year Demand-Side Management (DSM) plan for the 2025-2026 program years. The petition includes requested cost recovery of programs as well as performance incentives, depending on the level of success of the programs consistent with prior DSM plans. We expect the IURC to issue an order on this proceeding by the end of 2024.

AES Indiana Regulatory Rate Review — On April 17, 2024, the IURC issued an order (the “2024 Rate Order”) approving the Stipulation and Settlement Agreement that AES Indiana entered into on November 22, 2023, with the Office of Utility Consumer Counselor (“OUCC”) 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 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 4.90% on a rate base of approximately $3.5 billion. Updated customer rates and charges became effective on May 9, 2024.

AES Indiana Petersburg Repowering — On March 11, 2024, AES Indiana filed for approval of a CPCN seeking for IURC approval to repower Petersburg Generation Units 3 & 4 from coal to natural gas and to recover costs through future rates. The conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026 and the conversion of Unit 4 is expected to begin in June 2026 and be completed by December 2026. A hearing for this case is expected to be held in August 2024, and we expect the IURC to issue an order on this proceeding during the fourth quarter of 2024.

AES Ohio Smart Grid Phase 2 Filing — In February 2024, AES Ohio filed a Smart Grid Phase 2 with the PUCO proposing to invest approximately $683 million in capital projects over a 10-year period following the Smart Grid Phase 1, which ends June 2025.

Foreign Exchange Rates

We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the USD, and currencies of the countries in which we operate.

The overall economic climate in Argentina has deteriorated, resulting in volatility and increased the risk that a further significant devaluation of the Argentine peso against the USD, similar to the devaluations experienced by the country in 2018, 2019, and 2023, may occur. A continued trend of peso devaluation could result in increased inflation, a deterioration of the country’s risk profile, and other adverse macroeconomic effects that could significantly impact our results of operations. For additional information, refer to Item 3.—Quantitative and Qualitative Disclosures About Market Risk.

Impairments

Long-lived Assets and Current Assets Held-for-Sale — During the six months ended June 30, 2024, the Company recognized asset impairment expense of $276 million. See Note 16—Asset Impairment Expense included in Item 1.—Financial Statementsof this Form 10-Q for further information. After recognizing this impairment expense, the carrying value of long-lived assets and current assets held-for-sale that were assessed for impairment totaled $2.3 billion at June 30, 2024.

Events or changes in circumstances that may necessitate recoverability tests and potential impairments of

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long-lived assets may include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, evolving industry expectations to transition away from fossil fuel sources for generation, or an expectation it is more likely than not the asset will be disposed of before the end of its estimated useful life.

Environmental

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals) and certain air emissions, such as SO 2, NOx, particulate matter, mercury, and other hazardous air pollutants, and species and habitat protections. 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 included in the 2023 Form 10-K.

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, or interference with maintenance of, any NAAQS. The CSAPR required significant reductions in SO 2 and NOx emissions from power plants in many states in which subsidiaries of the Company operate. The Company is required to comply with the CSAPR in certain states, including Indiana and Maryland. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. The Company complies with CSAPR through operation of existing controls and purchases of allowances on the open market, as needed.

In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). The CSAPR Update Rule found that NOx ozone season emissions in 22 states (including Indiana and Maryland) affected the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and, accordingly, the EPA issued federal implementation plans that both updated existing CSAPR NOx ozone season emission budgets for electric generating units within these states and implemented these budgets through modifications to the CSAPR NOx ozone season allowance trading program. Implementation started in the 2017 ozone season (May-September 2017). Affected facilities receive fewer ozone season NOx allowances in 2017 and later, possibly resulting in the need to purchase additional allowances. Following legal challenges to the CSAPR Update Rule, on April 30, 2021, the EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected EGUs within certain states (including Indiana and Maryland) to participate in a new trading program, the CSAPR NOx Ozone Season Group 3 trading program. These affected EGUs received fewer NOx Ozone Season allowances beginning in 2021.

On June 5, 2023, the EPA published a final Federal Implementation Plan to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and Maryland, and became effective during 2023. The FIP also includes enhancements to the revised Group 3 trading program, which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels. It is too early to determine the impact of this final rule, but it may result in the need to purchase additional allowances or make operational adjustments. On June 27, 2024, the U.S. Supreme Court issued an order granting a stay of the EPA’s 2023 Federal Implementation Plan ("FIP") pending resolution of legal challenges to the FIP.

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.

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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. In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA and subsequently remanded MATS to the EPA without vacatur. On May 22, 2020, the EPA published a final finding that it is not “appropriate and necessary” to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units (“EGUs”) (reversing its prior 2016 finding), but that the EPA would not remove the source category from the CAA Section 112(c) list of source categories and would not change the MATS requirements. On March 6, 2023, the EPA published a final rule to revoke its May 2020 finding and reaffirm its 2016 finding that it is appropriate and necessary to regulate these emissions. On April 24, 2023, the EPA published a proposed rule, the MATS Risk and Technology Review (“RTR”) Rule to lower certain emissions limits and revise certain other aspects of MATS. On May 7, 2024, the EPA published a final rule to revise MATS for coal and oil-fired EGUs. The final rule became effective on July 8, 2024. The final rule lowers certain emissions limits and revises certain other aspects of MATS. 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.

Climate Change Regulation — The final NSPS for CO 2 emissions from new, modified, and reconstructed fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015. Several states and industry groups challenged the NSPS for CO 2 in the D.C. Circuit Court. On December 20, 2018, the EPA published proposed revisions to the final NSPS for new, modified, and reconstructed coal-fired electric utility steam generating units. The EPA proposed that the Best System of Emissions Reduction (“BSER”) for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration (“CCS”), which had been the BSER for these units in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal. Challenges to the GHG NSPS remain held in abeyance at this time. On May 23, 2023, the EPA published a proposed rule that would establish CO 2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023. 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.

On July 8, 2019, the EPA published the final Affordable Clean Energy (“ACE”) Rule which would have established CO 2 emission rules for existing power plants under CAA Section 111(d) and would have replaced the EPA's 2015 Clean Power Plan Rule (“CPP”). However, on January 19, 2021, the D.C. Circuit vacated and remanded the ACE Rule. Subsequently, on June 30, 2022, the Supreme Court reversed the judgment of the D.C. Circuit Court and remanded for further proceedings consistent with its opinion holding that the “generation shifting” approach in the CPP exceeded the authority granted to the EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate, holding pending challenges to the ACE Rule in abeyance while the EPA developed a replacement rule. On May 23, 2023, the EPA published a proposed rule that would vacate the ACE Rule and proposed New Source Performance Standards (“NSPSs”) that would establish emissions guidelines in the form of CO 2 emissions limitations for certain existing electric generating units (“EGUs”) and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as the EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operation to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s. 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 CO 2 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). We are still reviewing these rules. The impact of the rules, the results of further proceedings, and potential future greenhouse gas emissions regulations remain uncertain but could be material.

61 | The AES Corporation | June 30, 2024 Form 10-Q

Waste Management — On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills and surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. The primary enforcement mechanisms under this regulation would be actions commenced by the states and private lawsuits. On December 16, 2016, the Water Infrastructure Improvements for the Nation Act ("WIN Act") was signed into law. This includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. If this rule is finalized before Indiana or Puerto Rico establishes a state-level CCR permit program, AES CCR units in those locations could eventually be required to apply for a federal CCR permit from the EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. On August 28, 2020, the EPA published final amendments to the CCR Rule titled "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," that, among other amendments, required certain CCR units to cease waste receipt and initiate closure by April 11, 2021. The CCR Part A Rule also allowed for extensions of the April 11, 2021 deadline if the EPA determines certain criteria are met. Facilities seeking such an extension were required to submit a demonstration to the EPA by November 30, 2020. On January 11, 2022, the EPA released the first in a series of proposed determinations regarding CCR Part A Rule demonstrations and compliance-related letters notifying certain other facilities of their compliance obligations under the federal CCR regulations. The determinations and letters include interpretations regarding implementation of the CCR Rule. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. On June 28, 2024, the D.C. Circuit dismissed the challenges. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

On May 18, 2023, the EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR. On May 8, 2024, the EPA published final revisions to the CCR rule which are effective on November 8, 2024. The final revisions expand the scope of CCR units regulated by the CCR rule to include legacy surface impoundments, inactive surface impoundments, and CCR management units. We are still reviewing the final revisions. It is too early to determine the potential impact.

The CCR rule, current or proposed amendments to or interpretations of the CCR rule, 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.

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 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.

62 | The AES Corporation | June 30, 2024 Form 10-Q

Water Discharges— In June 2015, the EPA and the U.S. Army Corps of Engineers ("the Agencies") published a rule defining federal jurisdiction over waters of the U.S., known as the "Waters of the U.S." (“WOTUS”) rule. WOTUS defines the geographic reach and authority of the Agencies to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the proper 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 clear standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional.

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

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash, and more stringent effluent limitations for flue gas desulfurization wastewater. 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. We are still reviewing the rule and 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.