00130H204

The condensed consolidated financial statements included in Item 1.—Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our 2025 Form 10-K. Forward-Looking Information The following discussion may contain forward-looking statements regarding us, our business, prospects, and our results of operations, that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. These statements include, but are not limited to, statements regarding management’s intents, beliefs, and current expectations and typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “forecast,” “target,” “will,” “would,” “intend,” “believe,” “project,” “estimate,” “plan,” and similar words. Forward-looking statements are not intended to be a guarantee of future results, but instead constitute current expectations based on reasonable assumptions. Factors that could cause or contribute to such differences include, but are not limited to, the following: •the completion of the proposed transaction between AES and Horizon Parent, L.P. (the “Transaction”) on the anticipated terms and timing; •the risk that the conditions to the completion of the Transaction are not satisfied in a timely manner or at all; •potential litigation relating to the Transaction, including resulting expense or delay, and the effects of any outcomes related thereto; •the risk that disruptions from the Transaction will harm AES’ business, including current plans and operations; •the ability of AES to retain and hire key personnel through the consummation of the Transaction; •potential adverse reactions or changes to business relationships resulting from the announcement or completion of the Transaction; •continued availability of capital and financing, and rating agency actions; •certain restrictions during the pendency of the Transaction that may impact AES’ ability to pursue certain business opportunities or strategic transactions; •significant transaction costs associated with the Transaction; •the possibility that the Transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events; •the occurrence of any event, change, or other circumstance that could give rise to the termination of the Transaction, including in circumstances requiring AES to pay a termination fee or other expenses; •competitive responses to the Transaction; •the economic climate, particularly the state of the economy in the areas in which we operate, which impacts demand for electricity in many of our key markets, including the fact that the global economy faces considerable uncertainty for the foreseeable future, which further increases many of the risks discussed in our 2025 Form 10-K; •changes in the price of electricity at which our generation businesses sell into the wholesale market and our utility businesses purchase to distribute to their customers, and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk; •changes in the prices and availability of coal, gas, and other fuels (including our ability to have fuel transported to our facilities) and the success of our risk management practices, such as our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts; •changes in and access to the financial markets, particularly changes affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments, and other corporate purposes; •changes in inflation, demand for power, interest rates, and foreign currency exchange rates, including our ability to hedge our interest rate and foreign currency risk; •our ability to fulfill our obligations, manage liquidity and comply with covenants under our recourse and non-recourse debt, including our ability to manage our significant liquidity needs and to comply with covenants under our revolving credit facilities and other existing financing obligations; 46 | The AES Corporation | June 30, 2026 Form 10-Q •our ability to receive funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise; •changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria; •our ability to purchase and sell assets at attractive prices and on other attractive terms; •our ability to compete in markets where we do business; •our ability to operate power generation, transmission and distribution facilities, including managing availability, outages, and equipment failures; •our ability to manage our operational and maintenance costs and the performance and reliability of our generating plants, including our ability to reduce unscheduled down times; •our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow, such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these agreements; •variations in weather, especially mild winters and cooler summers in the areas in which we operate, the occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other storms and disasters, wildfires and low levels of wind or sunlight for our wind and solar facilities; •pandemics, or the future outbreak of any other highly infectious or contagious disease; •the performance of our contracts by our contract counterparties, including suppliers or customers; •severe weather and natural disasters; •our ability to manage global supply chain disruptions; •our ability to raise sufficient capital to fund development projects or to successfully execute our development projects; •the success of our initiatives in renewable energy projects and energy storage projects; •the availability of government incentives or policies that support the development of renewable energy generation projects; •our ability to execute on our strategies or achieve expectations related to environmental, social, and governance matters; •our ability to keep up with advances in technology; •changes in number of customers or in customer usage; •the operations of our joint ventures and equity method investments that we do not control; •our ability to achieve reasonable rate treatment in our utility businesses; •changes in laws, rules and regulations affecting our international businesses, particularly in developing countries; •changes in laws, rules and regulations affecting our utilities businesses, including, but not limited to, regulations which may affect competition, the ability to recover net utility assets and other potential stranded costs by our utilities; •changes in law resulting from new local, state, federal or international energy legislation and changes in political or regulatory oversight or incentives affecting our wind business and solar projects, our other renewables projects, and our initiatives in GHG reductions and energy storage, including government policies or tax incentives; •changes in environmental laws, including requirements for reduced emissions, GHG legislation, regulation, and/or treaties and CCR regulation and remediation; •changes in tax laws, including U.S. tax reform, and challenges to our tax positions; •the effects of litigation and government and regulatory investigations; •the performance of our acquisitions; •our ability to maintain adequate insurance; •decreases in the value of pension plan assets, increases in pension plan expenses, and our ability to fund defined benefit pension and other postretirement plans at our subsidiaries; •losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets; •changes in accounting standards, corporate governance, and securities law requirements; •our ability to maintain effective internal control over financial reporting; 47 | The AES Corporation | June 30, 2026 Form 10-Q •our ability to remediate any future material weakness; •our ability to attract and retain talented directors, management, and other personnel; •cyber-attacks and information security breaches; and •data privacy. These factors, in addition to others described in Item 1A.—Risk Factors of this Form 10-Q, Item 1A.—Risk Factors and Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2025 Form 10-K and subsequent filings with the SEC, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward-looking information. Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this report. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business. Overview of Our Business We are a diversified power generation and utility company organized into the following four SBUs, mainly organized by technology: Renewables (solar, wind, energy storage, and hydro generation facilities), Utilities (AES Indiana, AES Ohio, and AES El Salvador regulated utilities and their generation facilities), Energy Infrastructure (natural gas, LNG, coal, pet coke, diesel, and oil generation facilities), and New Energy Technologies (investments in Fluence, Maximo, the AI Fund, and other new and innovative energy technology businesses). For additional information regarding our business, see Item 1.—Business of our 2025 Form 10-K. We have two lines of business: generation and utilities. Our Renewables, Utilities, and Energy Infrastructure SBUs participate in our first business line, generation, in which we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. Our Utilities SBU participates in our second business line, utilities, in which we own and/or operate utilities to generate or purchase, transmit, distribute, and sell electricity to end-user customers in the residential, commercial, industrial, and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market. Our New Energy Technologies SBU includes investments in new and innovative technologies to support leading-edge greener energy solutions. Proposed Merger On March 1, 2026, The AES Corporation (the “Company” or “AES”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among the Company, Horizon Parent, L.P., a Delaware limited partnership (“Parent”), and Horizon Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of Parent (“Merger Sub”). Pursuant to the Merger Agreement, on the terms and subject to the conditions set forth therein, Merger Sub will merge with and into the Company (the “Merger”), with the Company continuing as the surviving corporation in the Merger. Parent is jointly controlled by investment vehicles affiliated with one or more funds, accounts or other entities managed or advised by Global Infrastructure Management, LLC and the EQT Infrastructure VI fund. For further details on this proposed transaction, see Item 1A.—Risk Factors and Note 1—Financial Statement Presentation included in Item 1.—Financial Statements of this Form 10-Q. Executive Summary Compared with last year, second quarter net income increased $537 million, from a net loss of $150 million to net income of $387 million. This increase is the result of the favorable impact from energy derivatives and higher contributions from development services in the U.S., higher energy and capacity sales and prices in the spot market, higher retail margin primarily at AES Ohio, losses on commencement of sales-type leases recognized in the prior year at AES Clean Energy Development, lower income tax expense, and a gain on sale of shares in Fluence; partially offset by the prior-year impact of derecognition of a valuation allowance on the loan receivable upon reclassifying Mong Duong from held-for-sale to held and used and lower contract sales volume and higher depreciation mainly due to the expiration of the Maritza PPA in Bulgaria. Adjusted EBITDA, a non-GAAP measure, increased $217 million, from $681 million to $898 million, driven by higher contributions from development services in the U.S., higher energy and capacity sales and prices in the spot market, the increase in ownership of Cochrane, and higher retail margin primarily at AES Ohio; partially offset by lower contract sales volume mainly due to the expiration of the Maritza PPA in Bulgaria. 48 | The AES Corporation | June 30, 2026 Form 10-Q Compared with last year, net income for the six months ended June 30, 2026 increased $885 million, from a net loss of $223 million to net income of $662 million. This increase is the result of higher contributions from development services and the favorable impact of energy derivatives in the U.S., higher retail margin and transmission and rider revenues at AES Ohio and AES Indiana, higher energy and capacity sales and prices in the spot market, losses on commencement of sales-type leases recognized in the prior year at AES Clean Energy Development, income tax benefit in the current year compared to income tax expense in the prior year, one-time costs in the prior year due to the Company’s restructuring program in February 2025, and a gain on sale of shares in Fluence; partially offset by the prior-year impact of derecognition of a valuation allowance on the loan receivable upon reclassifying Mong Duong from held-for-sale to held and used and lower contract sales volume and higher depreciation mainly due to the expiration of the Maritza PPA in Bulgaria. Adjusted EBITDA, a non-GAAP measure, increased $453 million, from $1,272 million to $1,725 million for the six months ended June 30, 2026, driven by higher contributions from development services in the U.S., higher energy and capacity sales and prices in the spot market, the increase in ownership of Cochrane, and higher retail margin and transmission and rider revenues at AES Ohio and AES Indiana; partially offset by the impact of the AES Ohio and AGIC selldowns in the prior year and lower contract sales volume mainly due to the expiration of the Maritza PPA in Bulgaria. 49 | The AES Corporation | June 30, 2026 Form 10-Q (1) Non-GAAP measure. See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition. (2) GWh sold in 2025. 50 | The AES Corporation | June 30, 2026 Form 10-Q Review of Consolidated Results of Operations (Unaudited) Three Months Ended June 30, Six Months Ended June 30, (in millions) 2026 2025 $ change % change 2026 2025 $ change % change Revenue: Renewables SBU $ 939 $ 644 $ 295 46 % $ 1,759 $ 1,310 $ 449 34 % Utilities SBU 1,018 954 64 7 % 2,154 1,963 191 10 % Energy Infrastructure SBU 1,496 1,306 190 15 % 2,752 2,626 126 5 % New Energy Technologies SBU — — — — % — — — — % Corporate and Other 39 43 (4) -9 % 68 79 (11) -14 % Eliminations (70) (92) 22 24 % (131) (197) 66 34 % Total Revenue 3,422 2,855 567 20 % 6,602 5,781 821 14 % Operating Margin: Renewables SBU 247 85 162 NM 410 158 252 NM Utilities SBU 158 136 22 16 % 391 291 100 34 % Energy Infrastructure SBU 241 176 65 37 % 442 365 77 21 % New Energy Technologies SBU (3) (4) 1 -25 % (6) (4) (2) 50 % Corporate and Other 64 84 (20) -24 % 129 142 (13) -9 % Eliminations (15) (24) 9 38 % (34) (58) 24 41 % Total Operating Margin 692 453 239 53 % 1,332 894 438 49 % General and administrative expenses (62) (49) (13) 27 % (117) (126) 9 -7 % Interest expense (368) (352) (16) 5 % (721) (694) (27) 4 % Interest income 65 70 (5) -7 % 130 139 (9) -6 % Loss on extinguishment of debt (6) (5) (1) 20 % (14) (13) (1) 8 % Other expense (27) (295) 268 -91 % (85) (347) 262 -76 % Other income 28 31 (3) -10 % 40 38 2 5 % Gain on disposal and sale of business interests 209 70 139 NM 209 69 140 NM Asset impairment reversals (expense) (30) 154 (184) NM (42) 105 (147) NM Foreign currency transaction losses (52) (28) (24) 86 % (41) (38) (3) 8 % Other non-operating expense — (10) 10 -100 % — (10) 10 -100 % Income tax benefit (expense) (28) (167) 139 -83 % 13 (184) 197 NM Net equity in losses of affiliates (34) (22) (12) 55 % (42) (56) 14 -25 % NET INCOME (LOSS) 387 (150) 537 NM 662 (223) 885 NM Less: Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries 39 55 (16) -29 % 251 174 77 44 % NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION $ 426 $ (95) $ 521 NM $ 913 $ (49) $ 962 NM Net cash provided by operating activities $ 1,046 $ 976 $ 70 7 % $ 2,247 $ 1,521 $ 726 48 % Components of Revenue, Cost of Sales, 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 Condensed 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, O&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. Operating margin is defined as revenue less cost of sales. 51 | The AES Corporation | June 30, 2026 Form 10-Q Consolidated Revenue and Operating Margin Three Months Ended June 30, 2026 Revenue (in millions) Consolidated Revenue — Revenue increased $567 million, or 20%, for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, driven by: •$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., $53 million due to new projects placed in service in the U.S. and Chile, $27 million positive impact due to the appreciation of the Colombian peso, and $21 million higher revenues under our retail supply agreements; partially offset by $13 million lower contracted and spot sales in Chile; •$190 million at Energy Infrastructure mainly driven by $188 million of higher energy 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 $72 million lower contract sales volume mainly driven by the expiration of the Maritza PPA in Bulgaria; •$64 million at Utilities mainly driven by $38 million due to higher retail rates as a result of AES Ohio’s 2024 DRC Settlement in November 2025, and $35 million due to higher transmission and rider revenues; partially offset by a $10 million decrease in wholesale revenues at AES Indiana driven by lower load requirements and unit availability; and •$18 million at Corporate, Other and Eliminations mainly driven by lower eliminations of inter-segment revenue. Operating Margin (in millions) Consolidated Operating Margin — Operating margin increased $239 million, or 53%, for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, mainly due to higher margins at the Renewables SBU driven by favorable impacts from energy derivatives and contributions from development services in the U.S., as well as higher energy and capacity sales and prices in the spot market at the Energy Infrastructure SBU. The increase in operating margin was partially offset by lower contract sales volume mainly due to the expiration of the Maritza PPA in Bulgaria. 52 | The AES Corporation | June 30, 2026 Form 10-Q See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-Q for additional discussion and analysis of operating results for each SBU. Six Months Ended June 30, 2026 Revenue (in millions) Consolidated Revenue — Revenue increased $821 million, or 14%, for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, driven by: •$449 million at Renewables mainly driven by $126 million due to development services in the U.S., a $93 million favorable impact from energy derivatives in the U.S., $90 million due to new projects placed in service in the U.S. and Chile, $48 million higher spot sales and prices in Colombia, mainly driven by El Niño and partially offset by lower spot prices in the first quarter, $40 million positive impact due to the appreciation of the Colombian peso, and $40 million higher revenues under our retail supply agreements; •$191 million at Utilities mainly driven by $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 $17 million increase in wholesale revenues at AES Indiana driven by higher load requirements and increased capacity from new renewables projects placed in service; •$126 million at Energy Infrastructure mainly driven by $201 million higher energy and capacity sales and prices in the spot 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 of prior year net derivative losses as part of our commercial hedging strategy; partially offset by $207 million lower contract sales volume mainly driven by the expiration of the Maritza PPA in Bulgaria; and •$55 million at Corporate, Other and Eliminations mainly driven by lower eliminations of inter-segment revenue, partially offset by lower charge-outs of IT and other costs to the businesses. Operating Margin (in millions) Consolidated Operating Margin — Operating margin increased $438 million, or 49%, for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, mainly due to higher margins at the Renewables SBU driven by contributions from development services in the U.S. and favorable impacts from energy derivatives, as well as higher retail rates at AES Ohio at the Utilities SBU, and higher energy and capacity sales and prices in the spot market at the Energy Infrastructure SBU. The increase in operating margin was partially offset by lower contract sales volume mainly due to the expiration of the Maritza PPA in Bulgaria and higher depreciation. 53 | The AES Corporation | June 30, 2026 Form 10-Q See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-Q for additional discussion and analysis of operating results for each SBU. Consolidated Results of Operations — Other General and administrative expenses General and administrative expenses increased $13 million, or 27%, to $62 million for the three months ended June 30, 2026, compared to $49 million for the three months ended June 30, 2025, primarily due to $11 million of costs related to the Merger and a $5 million increase in business development costs, partially offset by $3 million lower professional fees. General and administrative expenses decreased $9 million, or 7%, to $117 million for the six months ended June 30, 2026, compared to $126 million for the six months ended June 30, 2025, primarily due to a $14 million decrease in business development costs and $9 million decrease in one-time costs, all driven by the Company's restructuring program in February 2025, as well as $6 million lower professional fees; partially offset by $22 million of costs related to the Merger. Interest expense Interest expense increased $16 million, or 5%, to $368 million for the three months ended June 30, 2026, compared to $352 million for the three months ended June 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; partially offset by lower debt balances at the Energy Infrastructure SBU. Interest expense increased $27 million, or 4%, to $721 million for the six months ended June 30, 2026, compared to $694 million for the six months ended June 30, 2025. This increase is primarily due to 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. Other expense Other expense decreased $268 million, or 91%, to $27 million for the three months ended June 30, 2026, compared to $295 million for the three months ended June 30, 2025, primarily driven by $199 million of prior year losses on commencement of sales-type leases at AES Clean Energy, and a prior year $48 million loss on remeasurement of our investment in 5B, accounted for using the measurement alternative. Other expense decreased $262 million, or 76%, to $85 million for the six months ended June 30, 2026, compared to $347 million for the six months ended June 30, 2025, primarily driven by a $164 million decrease in losses on commencement of sales-type leases at AES Clean Energy, a prior year $48 million loss on remeasurement of our investment in 5B, accounted for using the measurement alternative, and a $20 million decrease in losses on remeasurement of contingent consideration. See Note 15—Other Income and Expense included in Item 1.—Financial Statements of this Form 10-Q for further information. Gain on disposal and sale of business interests Gain on disposal and sale of business interests increased $139 million to $209 million for the three months ended June 30, 2026, compared to $70 million for the three months ended June 30, 2025, mainly due to a $186 million gain on sale of shares of Fluence and a $24 million gain resulting from the contribution of two of the JK Projects to a trust; partially offset by a $70 million gain on the sell-down of Dominican Republic Renewables in the prior year. Gain on disposal and sale of business interests increased $140 million to $209 million for the six months ended June 30, 2026, compared to $69 million for the six months ended June 30, 2025 due to the drivers above. See Note 7—Investments in and Advances to Affiliates and Note 18—Held-for-Sale and Dispositions for further information. 54 | The AES Corporation | June 30, 2026 Form 10-Q Asset impairment reversals (expense) Asset impairment expense increased $184 million to $30 million for the three months ended June 30, 2026, compared to a $154 million reversal for the three months ended June 30, 2025. This increase was primarily the result of a $243 million increase in the carrying value of the Mong Duong asset group in the prior year due to the derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 and the elimination of net estimated costs to sell upon reclassifying Mong Duong from held-for-sale to held and used. This was partially offset by lower impairment expense of $54 million at AES Clean Energy Development due to the write-off of project development intangibles and capitalized development costs for projects that were determined to be no longer viable, mainly driven by $51 million in the prior year due to the right sizing of our development company as part of the restructuring program initiated in February 2025. Asset impairment expense increased $147 million to $42 million for the six months ended June 30, 2026, compared to a $105 million reversal for the six months ended June 30, 2025. This increase was primarily the result of a $243 million increase in the carrying value of Mong Duong asset group in the prior year due to the derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 and the elimination of net estimated costs to sell upon reclassifying Mong Duong from held-for-sale to held and used. This was partially offset by lower impairment expense of $79 million at AES Clean Energy Development due to the write-off of project development intangibles and capitalized development costs for projects that were determined to be no longer viable, mainly driven by $51 million in the prior year due to the right sizing of our development company as part of the restructuring program initiated in February 2025. See Note 16—Asset Impairment Expense included in Item 1.—Financial Statements of this Form 10-Q for further information. Foreign currency transaction losses Three Months Ended June 30, Six Months Ended June 30, (in millions) 2026 2025 2026 2025 Argentina $ (28) $ (10) $ (18) $ (10) Chile (22) (8) (23) (19) Corporate 1 (10) 3 (12) Other (3) — (3) 3 Total (1) $ (52) $ (28) $ (41) $ (38) ___________________________________________ (1)Includes losses of $36 million and $12 million on foreign currency derivative contracts for the three months ended June 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 $52 million for the three months ended June 30, 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 and the appreciation of the Colombian peso, which negatively impacted foreign currency forwards. The Company recognized net foreign currency transaction losses of $41 million for the six months ended June 30, 2026, primarily driven by unrealized losses in Chile due to the appreciation of the Colombian peso, which negatively impacted foreign currency forwards, higher realized foreign currency losses related to settled forward contracts in Chile, and unrealized foreign currency derivative losses in Argentina. The Company recognized net foreign currency transaction losses of $28 million and $38 million for the three and six months ended June 30, 2025, respectively, primarily driven by unrealized losses due to the appreciation of the Chilean peso and unrealized losses on forwards and options in Euros. Other non-operating expense There were no other non-operating expenses during the three and six months ended June 30, 2026. Other non-operating expense was $10 million for the three and six months ended June 30, 2025 due to an other-than-temporary impairment of convertible notes at 5B as a result of an observable price change from a transaction between 5B and a third-party. Income tax benefit (expense) Income tax expense decreased $139 million, or 83%, to $28 million for the three months ended June 30, 2026, compared to $167 million for the three months ended June 30, 2025. The Company’s effective tax rates were 6% and 428% for the three months ended June 30, 2026 and 2025, respectively. The current quarter effective tax rate 55 | The AES Corporation | June 30, 2026 Form 10-Q was impacted by the benefit associated with ITCs, as well as the benefit associated with the Fluence sell-down transaction due to release of valuation allowance on U.S. capital losses. These impacts were partially offset by tax expense resulting from allocations of losses to tax equity investors on renewables projects. See Note 7—Investments in and Advances to Affiliates included in Item 1.—Financial Statements of this Form 10-Q for additional information regarding the Fluence sell-down. Income tax benefit was $13 million for the six months ended June 30, 2026, compared to income tax expense of $184 million for the six months ended June 30, 2025. The Company’s effective tax rates were (2)% and 1,082% for the six months ended June 30, 2026 and 2025, respectively. The 2026 effective tax rate was impacted by the benefits associated with ITCs and the Fluence sell-down transaction, partially offset by tax expense resulting from allocations of losses to tax equity investors on renewables projects. The 2025 effective tax rate was not meaningful due to pretax book income being near breakeven. This effective tax rate was largely impacted by the benefits associated with U.S. investment tax credits (“ITCs”), the prior year reclassification of Mong Duong from held-for-sale to held and used, and tax expense resulting from allocations of losses to tax equity investors on renewables projects. Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates different than the U.S. statutory rate of 21%. Furthermore, our foreign earnings may be subjected to incremental U.S. taxation under the NCTI rules. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. Net equity in losses of affiliates Net equity in losses of affiliates increased $12 million, or 55%, to $34 million for the three months ended June 30, 2026, compared to $22 million for the three months ended June 30, 2025. This increase was primarily driven by a $22 million impact at Gatun due to current year debt extinguishment costs and higher losses of $11 million from Dominican Republic Renewables due to beginning equity method accounting in June 2025, partially offset by lower losses from Uplight of $5 million after equity method accounting was suspended in the fourth quarter of 2025 and from Fluence of $5 million driven by an increase in the volume of products fulfilled, as well as higher earnings from sPower of $7 million due to lower interest expense. Net equity in losses of affiliates decreased $14 million, or 25%, to $42 million for the six months ended June 30, 2026, compared to $56 million for the six months ended June 30, 2025. This decrease was primarily driven by lower losses from Uplight of $16 million after equity method accounting was suspended in the fourth quarter of 2025 and $10 million from sPower due to lower interest expense, as well as higher earnings from Fluence of $6 million driven by an increase in the volume of products fulfilled, partially offset by a $22 million impact at Gatun due to current year debt extinguishment costs. See Note 7—Investments in and Advances to Affiliates included in Item 1.—Financial Statements of this Form 10-Q for further information. Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $16 million, or 29%, to $39 million for the three months ended June 30, 2026, compared to $55 million for the three months ended June 30, 2025. This decrease in net losses was primarily due to: •Lower losses of $187 million at AES Clean Energy Development and AES Renewable Holdings due to prior-year losses on the commencement of sales-type leases and lower allocation of losses to tax equity investors on projects placed in service. This driver was partially offset by: •Lower income of $119 million at Mong Duong primarily due to the prior-year derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 upon reclassifying Mong Duong from held-for-sale to held and used; •Lower income of $25 million due to the prior-year deconsolidation of Dominican Republic Renewables; •Higher losses of $14 million at AES Indiana primarily related to higher allocation of losses to tax equity investors for the Petersburg Energy Center; and •Higher losses of $10 million in Panama primarily related to debt extinguishment costs. 56 | The AES Corporation | June 30, 2026 Form 10-Q Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries increased $77 million, or 44%, to $251 million for the six months ended June 30, 2026, compared to $174 million for the six months ended June 30, 2025. This increase in net losses was primarily due to: •Lower income of $112 million at Mong Duong primarily due to the prior-year derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 upon reclassifying Mong Duong from held-for-sale to held and used; •Higher losses of $72 million at AES Clean Energy Development primarily attributable to higher allocation of losses to tax equity investors on projects placed in service; •Lower income of $27 million due to the prior-year deconsolidation of Dominican Republic Renewables; •Lower income of $13 million due to the acquisition of the remaining shares of Cochrane; and •Higher losses of $12 million in Panama primarily related to debt extinguishment costs. These drivers were partially offset by: •Lower losses of $107 million at AES Renewable Holdings due to lower allocation of losses to tax equity investors on projects placed in service; •Higher income of $14 million and $12 million due to the prior-year selldowns of AES Ohio and AGIC, respectively; •Higher income of $10 million at Merida due to higher spot sales; and •Lower losses of $9 million at AES Indiana primarily related to higher allocation of losses to tax equity investors for the Pike County BESS project in the prior year. Net income attributable to The AES Corporation Net income attributable to The AES Corporation increased $521 million to $426 million for the three months ended June 30, 2026, compared to a $95 million loss for the three months ended June 30, 2025. This increase was primarily due to: •Lower other expense of $220 million primarily due to lower losses on commencement of sales-type leases and a prior-year loss on remeasurement of our investment in 5B, accounted for using the measurement alternative; •Higher gain on disposal and sale of business interests of $165 million due to a gain on sale of shares in Fluence and the contribution of JK1 and JK2 to a trust, partially offset by a prior-year gain on the sell-down of Dominican Republic Renewables; •Lower income tax expense of $140 million due to a lower effective tax rate; •Higher margins from the Renewables SBU of $126 million, excluding one-time restructuring costs in the prior year, primarily due to net favorable impact from energy derivatives in the U.S., increases from development services in the U.S., higher spot sales and prices driven by El Niño partially offset by lower contracted energy margin in Colombia, and appreciation of the Colombian peso; partially offset by higher depreciation; •Higher margins from the Energy Infrastructure SBU of $64 million, excluding one-time restructuring costs in the prior year, primarily due to higher energy and capacity sales and prices in the spot market and higher net derivative gains, partially offset by lower contract sales volume at Maritza due to the PPA expiration and higher depreciation at Maritza due to the useful life reassessment in the prior year; and •Higher margins from the Utilities SBU of $18 million primarily due to the 2024 DRC Settlement at AES Ohio, partially offset by higher property taxes. These drivers were partially offset by: •Prior-year $127 million increase in the carrying value of the Mong Duong asset group primarily due to the derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 upon reclassifying Mong Duong from held-for-sale to held and used; •Lower contributions from renewables projects placed in service of $70 million; and 57 | The AES Corporation | June 30, 2026 Form 10-Q •Higher foreign currency losses of $25 million primarily related to unrealized foreign currency derivative losses in Argentina and unrealized losses in Chile due to the appreciation of the Chilean peso and the appreciation of the Colombian peso, which negatively impacted foreign currency forwards. Net income attributable to The AES Corporation increased $962 million to $913 million for the six months ended June 30, 2026, compared to a $49 million loss for the six months ended June 30, 2025. This increase was primarily due to: •Lower other expense of $213 million primarily due to lower losses on commencement of sales-type leases and a prior-year loss on remeasurement of our investment in 5B, accounted for using the measurement alternative; •Income tax benefit of $63 million compared to prior year income tax expense of $143 due to a lower effective tax rate; •Higher margins from the Renewables SBU of $180 million, excluding one-time restructuring costs in the prior year, primarily due to increases from development services in the U.S., net favorable impact from changes in energy derivatives in the U.S, higher spot sales and prices driven by El Niño partially offset by lower contracted energy margin in Colombia, and appreciation of the Colombian peso; partially offset by higher depreciation; •Higher gain on disposal and sale of business interests of $164 million due to a gain on sale of shares in Fluence and the contribution of JK1 and JK2 to a trust, partially offset by a prior-year gain on the sell-down of Dominican Republic Renewables; •Higher contributions from renewables projects placed in service of $113 million; •Higher margins from the Energy Infrastructure SBU of $75 million, excluding one-time restructuring costs in the prior year, primarily due to higher energy and capacity sales and prices in the spot market, higher net derivative gains, and higher LNG sales, partially offset by lower contract sales volume at Maritza due to the PPA expiration and higher depreciation at Maritza due to the useful life reassessment in the prior year; •Higher margins from the Utilities SBU of $62 million, excluding one-time restructuring costs in the prior year, primarily due to the 2024 DRC Settlement and higher transmission revenues at AES Ohio and higher rider revenues at AES Indiana; partially offset by higher property taxes; •One-time restructuring costs of $50 million in the prior year; and •Lower net equity in losses of affiliates of $18 million primarily related to the suspension of equity method accounting at Uplight in the fourth quarter of 2025. These drivers were partially offset by: •Prior-year $127 million increase in the carrying value of the Mong Duong asset group primarily due to the derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 upon reclassifying Mong Duong from held-for-sale to held and used; and •Lower income of $30 million due to allocations of earnings to noncontrolling interest holders under profit-sharing arrangements based on stated internal rates of return. SBU Performance Analysis Non-GAAP Measures EBITDA, Adjusted EBITDA, and Adjusted PTC are non-GAAP supplemental measures that are used by management and external users of our condensed consolidated financial statements such as investors, industry analysts, and lenders. Beginning in the first quarter of 2026, the Company no longer discloses Adjusted EPS or Adjusted EBITDA with Tax Attributes. Both metrics are subject to significant variability related to the effect of Production Tax Credits (“PTCs”), Investment Tax Credits (“ITCs”), and depreciation tax deductions allocated to tax equity investors, as well as the tax benefit recorded from tax credits retained or transferred to third parties. As a result, the Company determined that these metrics are no longer as relevant to investors and Adjusted EBITDA better reflects the underlying business performance of the Company and is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. On March 1, 2026, the Company entered into the Merger Agreement. Pursuant to the Merger Agreement, 58 | The AES Corporation | June 30, 2026 Form 10-Q Merger Sub will merge with and into the Company (the “Merger”), with the Company continuing as the surviving corporation in the Merger. See Note 1—Financial Statement Presentation—Proposed Merger included in Item 1.—Financial Statements of this Form 10-Q for further information. During the first quarter of 2026, the Company updated the definitions of Adjusted EBITDA and Adjusted PTC to exclude costs directly associated with the Merger, including but not limited to, advisory, legal, and employee-related costs. This discrete, strategic transaction would result in significant incremental costs above normal operations, and the inclusion of such costs would result in a lack of comparability in our results of operations and could be misleading to investors. We believe excluding these costs associated with the Merger better reflects the underlying business performance of the Company. During the first quarter of 2025, the Company updated the definition of Adjusted EBITDA and Adjusted PTC to exclude costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts. These restructuring initiatives to streamline our organization and right-size our development company would result in significant incremental costs above normal operations, and the inclusion of such costs would result in a lack of comparability in our results of operations and could be misleading to investors. We believe excluding these costs associated with a major restructuring initiative better reflects the underlying business performance of the Company. EBITDA and Adjusted EBITDA We define EBITDA as earnings before interest income and expense, taxes, depreciation, amortization, and accretion of AROs. We define Adjusted EBITDA as EBITDA adjusted for the impact of NCI and interest, taxes, depreciation, and amortization of our equity affiliates, adding back interest income recognized under service concession arrangements, and excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses pertaining to derivative transactions, equity securities, and financial assets and liabilities measured using the fair value option; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses, and costs due to the early retirement of debt or troubled debt restructuring; (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts; and (g) costs directly associated with the Merger, including, but not limited to, advisory, legal, and employee-related costs. In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted EBITDA includes the other components of our Condensed Consolidated Statements of Operations, such as general and administrative expenses in Corporate and Other as well as business development costs, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings (losses) of affiliates. The GAAP measure most comparable to EBITDA and Adjusted EBITDA is Net income. We believe that EBITDA and Adjusted EBITDA better reflect the underlying business performance of the Company. Adjusted EBITDA is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses pertaining to derivative transactions, equity securities, or financial assets and liabilities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests, retire debt, implement restructuring initiatives, or consummate the Merger, and the variability of allocations of earnings to tax equity investors, which affect results in a given period or periods. In addition, each of these metrics represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Given its large number of businesses and overall complexity, the Company concluded that Adjusted EBITDA is a more transparent measure than Net income that better assists investors in determining which businesses have the greatest impact on the Company’s results. EBITDA and Adjusted EBITDA should not be construed as alternatives to Net income, which is determined in accordance with GAAP. 59 | The AES Corporation | June 30, 2026 Form 10-Q Three Months Ended June 30, Six Months Ended June 30, Reconciliation of Adjusted EBITDA (in millions) 2026 2025 2026 2025 Net income (loss) $ 387 $ (150) $ 662 $ (223) Income tax expense (benefit) 28 167 (13) 184 Interest expense 368 352 721 694 Interest income (65) (70) (130) (139) Depreciation, amortization, and accretion of AROs 434 354 867 691 EBITDA $ 1,152 $ 653 $ 2,107 $ 1,207 Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1) (199) (253) (431) (387) Less: Income tax expense (benefit), interest expense (income) and depreciation, amortization, and accretion of AROs from equity affiliates 52 45 85 81 Interest income recognized under service concession arrangements 14 14 27 29 Unrealized derivatives, equity securities, and financial assets and liabilities losses 27 133 20 132 Unrealized foreign currency losses (gains) 12 4 (8) (3) Disposition/acquisition losses (gains) (209) 126 (156) 167 Impairment losses (reversals) 24 (87) 34 (54) Loss on extinguishment of debt and troubled debt restructuring 12 4 20 12 Restructuring costs — 42 — 88 Merger costs 13 — 27 — Adjusted EBITDA (1) $ 898 $ 681 $ 1,725 $ 1,272 ______________________________ (1) The allocation of earnings and losses to tax equity investors from both consolidated entities and equity affiliates is removed from Adjusted EBITDA. NCI also excludes amounts allocated to preferred shareholders during the construction phase before a project becomes operational, as this is akin to a financing arrangement. 60 | The AES Corporation | June 30, 2026 Form 10-Q Adjusted PTC We define Adjusted PTC as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses pertaining to derivative transactions, equity securities, and financial assets and liabilities measured using the fair value option; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits, and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses, and costs due to the early retirement of debt or troubled debt restructuring; (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts; and (g) costs directly associated with the Merger, including, but not limited to, advisory, legal, and employee-related costs. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities. Adjusted PTC reflects the impact of NCI and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our Condensed Consolidated Statements of Operations, such as general and administrative expenses in Corporate and Other as well as business development costs, interest expense and interest income, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings (losses) of affiliates. The GAAP measure most comparable to Adjusted PTC is Income from continuing operations attributable to The AES Corporation. We believe that Adjusted PTC better reflects the underlying business performance of the Company and is a relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses pertaining to derivative transactions, equity securities, or financial assets and liabilities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, and strategic decisions to dispose of or acquire business interests, retire debt, implement restructuring initiatives, or consummate the Merger, which affect results in a given period or periods. In addition, Adjusted PTC represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure than Income from continuing operations attributable to The AES Corporation that better assists investors in determining which businesses have the greatest impact on the Company’s results. Adjusted PTC should not be construed as an alternative to Income from continuing operations attributable to The AES Corporation, which is determined in accordance with GAAP. 61 | The AES Corporation | June 30, 2026 Form 10-Q Three Months Ended June 30, Six Months Ended June 30, Reconciliation of Adjusted PTC (in millions) 2026 2025 2026 2025 Income (loss) from continuing operations, net of tax, attributable to The AES Corporation $ 426 $ (95) $ 913 $ (49) Income tax expense (benefit) from continuing operations attributable to The AES Corporation 7 148 (63) 144 Pre-tax contribution 433 53 850 95 Unrealized derivatives, equity securities, and financial assets and liabilities losses 27 133 20 128 Unrealized foreign currency losses (gains) 12 4 (8) (3) Disposition/acquisition losses (gains) (209) 125 (156) 167 Impairment losses (reversals) 24 (87) 34 (54) Loss on extinguishment of debt and troubled debt restructuring 14 6 25 16 Restructuring costs — 42 — 88 Merger costs 13 — 27 — Adjusted PTC $ 314 $ 276 $ 792 $ 437 62 | The AES Corporation | June 30, 2026 Form 10-Q Renewables SBU The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 $ Change % Change 2026 2025 $ Change % Change Operating Margin $ 247 $ 85 $ 162 NM $ 410 $ 158 $ 252 NM Adjusted EBITDA (1) 369 240 129 54 % 638 401 237 59 % _____________________________ (1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition. Operating Margin for the three months ended June 30, 2026 increased $162 million, primarily driven by a $76 million favorable impact from energy derivatives in the U.S., $62 million due to development services in the U.S., $34 million higher spot sales and prices driven by El Niño, partially offset by lower contracted energy margin in Colombia, and $11 million positive impact due to the appreciation of the Colombian peso; partially offset by $14 million due to higher depreciation. Adjusted EBITDA for the three months ended June 30, 2026 increased $129 million, primarily due to the drivers above, adjusted for NCI, unrealized derivatives, and depreciation and amortization. Operating Margin for the six months ended June 30, 2026 increased $252 million, primarily driven by $123 million due to development services in the U.S., a $93 million favorable impact from energy derivatives in the U.S., $27 million higher spot sales and prices driven by El Niño, partially offset by lower contracted energy margin in Colombia, $17 million due to one-time restructuring costs incurred in the prior year, and $15 million positive impact due to the appreciation of the Colombian peso; partially offset by $36 million due to higher depreciation. Adjusted EBITDA for the six months ended June 30, 2026 increased $237 million, primarily due to the drivers above, adjusted for NCI, unrealized derivatives, restructuring costs, and depreciation and amortization. Utilities SBU The following table summarizes Operating Margin, Adjusted EBITDA, and Adjusted PTC (in millions) for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 $ Change % Change 2026 2025 $ Change % Change Operating Margin $ 158 $ 136 $ 22 16 % $ 391 $ 291 $ 100 34 % Adjusted EBITDA (1) 217 196 21 11 % 486 419 67 16 % Adjusted PTC (1) (2) 86 57 29 51 % 245 178 67 38 % ____________________________ (1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition. (2) Adjusted PTC remains a key metric used by management for analyzing our businesses in the utilities industry. Operating Margin for the three months ended June 30, 2026 increased $22 million, primarily driven by $38 million due to higher retail rates as a result of AES Ohio’s 2024 DRC Settlement in November 2025, including the impact of certain riders now incorporated into base rates. This increase was partially offset by a $15 million increase in fixed costs mainly driven by higher property taxes due to higher assessed values. Adjusted EBITDA for the three months ended June 30, 2026 increased $21 million, primarily due to the drivers above and adjusted for NCI. Adjusted PTC for the three months ended June 30, 2026 increased $29 million due to the drivers above. Operating Margin for the six months ended June 30, 2026 increased $100 million, primarily driven by $84 million due to higher retail rates as a result of AES Ohio’s 2024 DRC Settlement in November 2025, including the impact of certain riders now incorporated into base rates, and a $31 million increase due to higher transmission and rider revenues. These increases were partially offset by a $16 million increase in fixed costs mainly driven by higher property taxes due to higher assessed values. Adjusted EBITDA for the six months ended June 30, 2026 increased $67 million, primarily due to the drivers above and adjusted for NCI, including the impact of the AES Ohio selldown in the second quarter of 2025. Adjusted PTC for the six months ended June 30, 2026 increased $67 million due to the drivers above. 63 | The AES Corporation | June 30, 2026 Form 10-Q Energy Infrastructure SBU The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 $ Change % Change 2026 2025 $ Change % Change Operating Margin $ 241 $ 176 $ 65 37 % $ 442 $ 365 $ 77 21 % Adjusted EBITDA (1) 317 254 63 25 % 623 508 115 23 % _____________________________ (1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition. Operating Margin for the three months ended June 30, 2026 increased $65 million, primarily driven by $98 million higher energy and capacity sales and prices in the spot market, and $37 million driven by net derivative gains; partially offset by $48 million lower contract sales volume mainly due to the expiration of the Maritza PPA in Bulgaria, $15 million higher depreciation at Maritza due to the useful life reassessment in the prior year, and $12 million driven by lower availability. Adjusted EBITDA for the three months ended June 30, 2026 increased $63 million, primarily due to the drivers above, adjusted for unrealized derivatives, as well as higher depreciation at Maritza due to the useful life reassessment in the prior year, the increase in ownership of Cochrane, and higher equity earnings mainly at Gatun, excluding debt extinguishment costs. Operating Margin for the six months ended June 30, 2026 increased $77 million, primarily driven by $127 million higher energy and capacity sales and prices in the spot market, $33 million due to higher net derivative gains, $20 million lower fixed costs mainly due to the 2025 restructuring, and $11 million driven by higher LNG sales; partially offset by $65 million driven by lower contract sales volume mainly due to the expiration of the Maritza PPA in Bulgaria, $39 million higher depreciation at Maritza due to the useful life reassessment in the prior year, and $14 million driven by lower availability. Adjusted EBITDA for the six months ended June 30, 2026 increased $115 million, primarily due to the drivers above, adjusted for unrealized derivatives and restructuring costs, as well as higher depreciation at Maritza due to the useful life reassessment in the prior year, the increase in ownership of Cochrane, and higher equity earnings mainly at Gatun, excluding debt extinguishment costs. New Energy Technologies SBU The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 $ Change % Change 2026 2025 $ Change % Change Operating Margin $ (3) $ (4) $ 1 -25 % $ (6) $ (4) $ (2) 50 % Adjusted EBITDA (1) (14) (17) 3 -18 % (35) (42) 7 17 % _____________________________ (1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition. Operating Margin for the three months ended June 30, 2026 increased $1 million, with no material drivers. Adjusted EBITDA for the three months ended June 30, 2026 increased $3 million, with no material drivers. Operating Margin for the six months ended June 30, 2026 decreased $2 million, with no material drivers. Adjusted EBITDA for the six months ended June 30, 2026 increased $7 million, primarily due to lower losses from Uplight of $6 million after equity method accounting was suspended in the fourth quarter of 2025. Key Trends and Uncertainties During 2026 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, 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.—Business and Item 1A.—Risk Factors of our 2025 Form 10-K. 64 | The AES Corporation | June 30, 2026 Form 10-Q Operational Trade Restrictions and Supply Chain — In April 2022, the U.S. Department of Commerce (“Commerce”) initiated an investigation into whether imports into the U.S. of solar cells and panels from Cambodia, Malaysia, Thailand, and Vietnam (“Southeast Asia”) were circumventing antidumping and countervailing duty (“AD/CVD”) orders on solar cells and panels from China. In August 2023, Commerce rendered final affirmative findings of circumvention with respect to all four countries, which resulted in the imposition of AD/CVD duties on certain imported cells and panels from Southeast Asia. Commerce’s determination and related matters remain the subject of ongoing litigation before the U.S. Court of Appeals for the Federal Circuit (“Federal Circuit”). In 2024, Commerce and the U.S. International Trade Commission (“ITC”) initiated new AD/CVD investigations on solar cells and panels imported from Southeast Asia. On April 18, 2025, Commerce rendered final affirmative determinations and AD/CVD rates with respect to all four countries. On June 13, 2025, the ITC issued its determination that imports from Malaysia and Vietnam have injured the U.S. industry and that imports from Cambodia and Thailand threaten injury. Commerce then issued orders on June 24, 2025, implementing the AD/CVD rates, which will be subject to annual review by Commerce. There is ongoing litigation about these and related matters in the U.S. Court of International Trade ("CIT"). We do not expect these AD/CVD orders will have a negative impact on our business. The U.S. also maintains tariffs under Section 301 of the Trade Act of 1974 (“Section 301”) on certain Chinese made lithium-ion batteries and related components utilized for energy storage systems, with such tariffs currently set at 25% effective January 1, 2026 (an increase from the previous rate of 7.5%). Commerce has also conducted AD/CVD investigations with respect to exports by China of natural and synthetic graphite used to make lithium-ion battery anode material. In March 2026, the ITC issued a negative determination in its companion investigation, and therefore no AD/CVD orders will issue on anode material from China. Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China, at any point in the supply chain, and may lead to certain suppliers being blocked from importing solar cells and panels into the U.S. While this has impacted the U.S. market, AES has managed this issue without significant impact to our projects. Further forced labor designations of entities under the UFLPA 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. The Trump Administration has threatened or imposed tariffs on a wide range of countries and products. On February 10, 2025, President Trump signed Executive Orders modifying existing tariffs under Section 232 of the Trade Expansion Act of 1962 ("Section 232") on steel and aluminum imports to expand their scope and impose 25% tariffs on both products. The President raised these rates to 50% effective June 4, 2025. Starting in August 2025, the President imposed Section 232 tariffs on imported copper products and copper-intensive derivative products. In April 2026, the President issued a new Proclamation applying a tariff rate of 50% on articles wholly of steel, aluminum, or copper, and a rate of 25% on derivative products substantially made of those metals, in each case assessed on the full customs value of the imported article. In June 2026, the President further adjusted these tariff regimes. At this time, we do not expect the modifications to tariffs on steel, aluminum, and copper will have a material impact on our business. On February 1, 2025, President Trump issued an Executive Order declaring a national emergency under the International Emergency Economic Powers Act (“IEEPA”) with respect to U.S. importation of fentanyl and imposing tariffs on Mexico, Canada, and China. On April 2, 2025, the President issued an Executive Order pursuant to IEEPA imposing reciprocal tariffs on almost all goods imported into the U.S. In February 2026, on review of lower court decisions declaring the tariffs unlawful, the Supreme Court issued a decision holding that IEEPA does not authorize tariffs. In response, the President issued new 10% tariffs on almost all trading partners under Section 122 of the Trade Act of 1974, which expired on July 24, 2026. The Section 122 tariffs are currently under review by the Federal Circuit, following a May 2026 ruling from the CIT finding them to be unlawful. There has been no material impact on the Company from these Section 122 tariffs. In March 2026, the Office of the U.S. Trade Representative (“USTR”) initiated investigations under Section 301 concerning possible persistent trade surpluses and unused capacity with respect to China, the EU, South Korea, and certain other major trading partners. These investigations are ongoing. In March 2026, the USTR also initiated Section 301 investigations on 60 countries regarding potential failures to take action on forced labor. Effective July 24, 2026, the USTR imposed tariffs ranging from 10% to 12.5% stemming from the investigations concerning forced labor. The impact of these new and potential Section 301 tariffs on the Company is uncertain. 65 | The AES Corporation | June 30, 2026 Form 10-Q In July 2025, Commerce initiated a Section 232 investigation to determine the effects on national security of imports of polysilicon and its derivatives. In August 2025, Commerce initiated a separate investigation under Section 232 to determine the effects on national security of imports of wind turbines and their parts and components. These investigations are ongoing and their outcomes are uncertain. In January 2026, President Trump issued a Proclamation under Section 232 concerning the importation of several critical minerals (including graphite and lithium) from any country. The Proclamation does not impose tariffs on the critical minerals but directs Commerce and USTR to negotiate agreements with foreign partners to secure reliable access to the critical minerals. An update on the outcome or status of these negotiations was to be provided to the President within 180 days of the Proclamation, but the update has not been provided to date. If the negotiations fail to result in agreements or to adequately address the identified risks, the President may consider trade-restrictive measures with respect to the critical minerals. The outcome of this process as well as its potential impact on the Company are uncertain. The Trump Administration has reached bilateral trade agreements or frameworks with several trading partners (including the EU, Japan, and South Korea, among others). Trade negotiations are ongoing with many trading partners concerning various goods and industry sectors. In July 2026, the Federal Communications Commission (“FCC”) updated its “Covered List” to include new foreign-produced power inverters, thereby generally prohibiting such inverters from receiving FCC authorization to be imported, marketed, or sold in the U.S. However, the FCC’s action does not affect the continued importing, marketing, or selling of existing models of power inverters that have already received FCC equipment authorization or the continued use of such devices that have already been purchased. In addition, entities may seek “Conditional Approval” to import and sell new foreign-produced power inverters. At this time, we do not believe this action by the FCC will have a significant impact on our solar and battery projects under development. We expect the tariffs on imports from China will increase overall costs for materials and parts that are imported to build and maintain renewable energy plants for the U.S. industry. However, AES has already shifted its supply chain outside of China for the vast majority of final products used to build and maintain renewable energy plants in the U.S. We expect limited impact to projects scheduled to become operational in 2026 through 2027 due to the announced tariffs on China. The impact of new tariffs, U.S. Government investigations, proclamations, or actions, any additional adverse Commerce determinations or other tariff disputes or litigation, the UFLPA, and new or existing trade deals or frameworks, and the potential future disruptions to the renewable energy supply chain and their effect on AES’ U.S. 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 renewable energy projects. To that end, we have accelerated imports into the U.S. and increased our contracting for U.S. domestically manufactured solar panels, batteries, wind turbines, trackers, and other equipment, significantly mitigating the potential impacts from reciprocal tariffs or other tariffs. For our U.S backlog of solar projects scheduled to finish construction and become operational in 2026 or 2027, we have contracted for most of our panel supply needs, with the majority of such panels being manufactured in the U.S. and most of the remaining panels having already been imported into the U.S. These remaining imports are expected to be largely insulated from AD/CVD measures and potential Section 232 outcomes. Imports will exclude modules from countries currently subject to AD/CVD orders. Additionally, for our U.S. backlog of storage projects scheduled to finish construction and become operational in 2026 or 2027, we have contracted all our battery needs, with almost all of such batteries coming from U.S. or South Korean suppliers. We have also completed contracting of U.S. domestically manufactured battery modules to support the remainder of our U.S. energy storage growth through 2027. For our U.S. backlog of wind projects scheduled to be completed in 2026, we have contracted and received delivery of all turbines, and for our 2027 backlog of U.S. wind projects, we are fully contracted with U.S. suppliers and suppliers with primarily U.S. manufactured turbines. El Niño Impacts and Operational Sensitivity to Dry Hydrological Conditions — On July 9, 2026, the National Oceanographic and Atmospheric Administration (“NOAA”) declared an El Niño advisory. There is a forecast consensus across agencies, including the International Research Institute for Climate and Society (“IRI”) along with the NOAA, for strong-to-record-setting El Niño conditions in late 2026 into 2027. These conditions have traditionally led to strong weather impacts across the AES markets. 66 | The AES Corporation | June 30, 2026 Form 10-Q 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, Colombia, and Chile can present challenges for our businesses in these markets. Low inflows can result in low reservoir levels in these systems, 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. In Panama, while the first quarter 2026 system inflows supported the Bayano and Fortuna reservoirs remaining at above-average levels, the second quarter was much drier, leading to the first half of the year closing with lower than average reservoir levels. That said, the presence of Gatun, AES’s new combined cycle gas power plant, has reduced price and volatility, due to the displacement of other thermal generation. In Colombia, the first half of the year has been slightly wetter than average. The AES Chivor reservoir level remained elevated, and other major reservoirs are at approximately average levels. In general, El Niño conditions in Colombia are characterized by dry conditions in the system, causing spot prices generally to be elevated in El Niño seasons. The basin where AES Chivor is located typically experiences conditions that are less dry. Should the less-dry conditions at AES Chivor not materialize, it may require an increase in purchased power to cover contracted positions. In Chile, the first half of 2026 has remained very dry; however, it was marked by a structural decoupling of hydrology and the energy matrix. The power system demonstrated unprecedented resilience by offsetting the decline in hydroelectricity with record-breaking solar and wind generation, while leveraging the accelerated integration of BESS to mitigate curtailment, stabilize prices, and compensate for depleted system reservoirs. In the U.S., current seasonal outlooks favor above-normal winter temperatures across the midwestern U.S. during the 2026-2027 heating season, which, if realized, could result in lower retail electric sales during the fourth quarter of 2026 and first quarter of 2027 relative to normal weather assumptions. If actual conditions materialize consistent with the forecast consensus, demand at our U.S. utilities businesses may decrease significantly and the resulting impact could be material to the Company’s results of operations, financial condition, and cash flows. The exact behavior pattern and strength of weather transitions (from/to La Niña or El Niño) is unknown and therefore the impacts could vary from those described above, and may include impacts across our businesses, including with respect to power generation from other renewable sources of energy and demand. Even if rainfall and water inflows remain in line with historical averages, in some cases, market prices and generation above or below the average could present due to a variety of factors related to demand, market dynamics, or regulatory impacts. Impacts may be material to our results of operations. Macroeconomic and Political The macroeconomic and political environments in some countries where our subsidiaries conduct business have changed. This could result in significant impacts to tax laws and environmental and energy policies. Additionally, we operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level. U.S. Tax Law Reform and U.S. Renewable Energy Tax Credits — On July 4, 2025, the U.S. enacted H.R. 1 (the “2025 Act”). The legislation significantly revised the laws governing U.S. renewable energy tax credits and the U.S. taxation of certain foreign earnings, which may impact our effective tax rate in future periods and could be material. In addition, the 2025 Act included amendments to, and extensions of, various other U.S. corporate income tax provisions including the determination of limitation on interest expense deductions. Any impact may change as U.S. Treasury and Internal Revenue Service (“IRS”) issue additional guidance, which may be material. The U.S. Inflation Reduction Act of 2022 (the “IRA”) included provisions that benefited 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. 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. This method recognizes the value of the tax credit that benefits the tax equity investors at the time of its creation, which for projects utilizing the investment tax credit, begins in the quarter the renewables project is placed in service. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy. 67 | The AES Corporation | June 30, 2026 Form 10-Q The 2025 Act amends the phase out of wind and solar ITC and PTC tax credits. Wind and solar renewables projects that begin construction within 12 months of the enactment of the 2025 Act remain eligible for 100% of the credit without the 2027 placed-in-service deadline, provided that, under current Treasury guidance, the projects are placed in service no more than four calendar years after the calendar year when construction began. Wind and solar projects that begin construction after 12 months of the enactment must be placed in service no later than 2027. Wind and solar projects that began construction by the end of 2024 are not impacted by the 2025 Act. The 2025 Act does not impose tighter timelines for energy storage projects to qualify for the ITC and PTC, and it allows energy storage projects to receive the full ITC or PTC credit if they begin construction by 2033. The 2025 Act also imposes a restriction precluding credits for renewables and storage projects claiming the ITC or PTC credit that start construction after December 31, 2025 and receive material assistance from a prohibited foreign entity, effectively limiting the percentage of total project costs that may be derived from products that are mined, produced or manufactured in China, with varying permissible percentages depending on the calendar year and applicable technology for the project. This restriction also precludes credit eligibility for taxpayers owning projects that start construction after December 31, 2024 that are classified as having ownership or certain other interests by a prohibited foreign entity, including projects over which a prohibited foreign entity is deemed to exercise formal or effective control. Further, President Trump issued an Executive Order on July 7, 2025 that directed the Secretary of the Treasury to take action to enforce the provisions of the 2025 Act related to issuing updated guidance defining the start of construction for claiming the ITC and PTC and implementing the Foreign Entity of Concern (“FEOC”) Restrictions (the “Treasury Action”). The Executive Order also directed the Secretary of the Interior to take action to review its regulations, guidance, policies, and practices for any preferential treatment of wind and solar projects and eliminate those preferences within 45 days (the “Interior Action”). On August 15, 2025, the Department of Treasury issued updated guidance defining the start of construction for purposes of claiming the ITC and PTC. AES does not expect the modifications to the start of construction guidance to materially impact its projects. The Department of Treasury has not yet issued comprehensive guidance implementing the FEOC restrictions, however. Further guidance, which may be material, is expected to be released within the coming months. We expect the vast majority of our renewables project backlog to continue to qualify for the ITC and PTC. However, the Treasury Action may impose additional burdens in qualifying for the ITC and PTC. In response to the Executive Order, the Department of Interior issued a memorandum requiring any “decisions, actions, consultations, and other undertakings” for wind or solar projects under Department of Interior jurisdiction to go through an additional three-phase approval process ending with approval from the Secretary of the Interior. Our U.S. wind and solar projects are developed primarily on private land and are designed in a manner that minimizes the potential of a federal nexus. However, due to the broad language of the memorandum, there may be some impact to projects developed on private land. The enactment of the 2025 Act requires that substantial guidance be published by the U.S. Department of Treasury and other government agencies. While we have taken significant measures to protect against the impact of changes under the 2025 Act to the IRA, including by implementing a program designed to ensure our backlog of U.S. renewables projects satisfy IRS safe harbor requirements for qualifying for the ITCs and PTCs, the impacts of the 2025 Act, the Treasury Action, the Interior Action or future actions that have the effect of modifying or repealing the ITCs and PTCs or adversely impacting renewable energy projects may be material to our results of operations. Net CFC Tested Income (“NCTI”) — The 2025 Act amended the Global Intangible Low-Taxed Income (“GILTI”) provision by eliminating the reduction to foreign earnings subject to GILTI by an allowable economic return on investment beginning January 1, 2026. The GILTI provision was also renamed to the NCTI provision. Additionally, the 2025 Act modified the U.S. foreign tax credit provisions beginning January 1, 2026. Although the new NCTI rules provide for a reduced 14 percent effective tax rate on captured foreign income, by way of a 40 percent deduction, companies with a U.S. net operating loss or otherwise insufficient taxable income will not benefit from the lower effective tax rate and may not be able to utilize foreign tax credits. The new NCTI rules subject a portion of our foreign earnings to current U.S. taxation now and in the future and may be material. Limitation on Interest Expense Deductions — The 2025 Act retroactively amended the existing limitation on the deductibility of net interest expense beginning January 1, 2025. As amended, the deduction will be limited to interest income, plus 30% of tax basis EBITDA. Previously, the limitation was based on 30% of tax basis Earnings Before Interest and Taxes (“EBIT”). We expect the amendment to increase the current period permitted interest deductions 68 | The AES Corporation | June 30, 2026 Form 10-Q and reduce the amount of disallowed interest expense subject to an indefinite carryforward. The limitation continues to be inapplicable to interest expense attributable to regulated utility property. 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. For example, we are monitoring legislation in Chile that may decrease the income tax rate. Any such reduction could have material non-cash impacts to the Company. Also, in the U.S., the IRA included a 15% corporate alternative minimum tax (“CAMT”) based on adjusted financial statement income. In June 2025, the IRS began releasing interim guidance for CAMT and announced its intention to revise regulations that were proposed in September 2024. The impact to the Company in 2026 is not expected to be material. We will continue to monitor the issuance of CAMT revised guidance. The Netherlands, Bulgaria, Vietnam, and certain other jurisdictions adopted legislation to implement Pillar 2 effective as of January 1, 2024. On January 5, 2026, the Organisation for Economic Co-operation and Development (“OECD”) published a side-by-side package to modify the Pillar 2 system in a manner that will fully exclude domestic and foreign profits of US-parented groups from Pillar 2’s Undertaxed Profits Rule and Income Inclusion Rule. The side-by-side package is intended to take effect as of January 1, 2026, but is subject to enactment of legislation in the local jurisdictions, including Bulgaria, the Netherlands, the United Kingdom, and Spain. We will continue to monitor the issuance of legislation incorporating the side-by-side package, as well as other Pillar 2 amendments and new interpretive guidance in non-EU countries where the Company operates. 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 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 allow for recovery of O&M 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 was a rise in interest rates during 2021 through 2023, 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. 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. Argentina — In July 2024, the Argentine government enacted Law 27,742, known as Ley Bases, declaring a one-year public emergency in administrative, economic, financial, and energy matters. It grants the President delegated powers and initiates broad state reforms to deregulate the economy, including labor reform, the Incentive Regime for Large Investments, modifications to non-income tax measures, and the privatization of state-owned energy companies. Additionally, the Ministry of Energy issued Resolution 150/2024, repealing certain regulations from previous years that involved excessive state and CAMMESA intervention in the Wholesale Electricity Market (“MEM”). On January 28, 2025, the Energy Secretariat issued Resolution 21/2025 to reform the MEM and is intended to ensure secure energy supply and stable consumer costs. On April 11, 2025, the Central Bank of Argentina started a new economic program supported by a $20 billion agreement with the International Monetary Fund. The key points of the program include (a) a removal of exchange restrictions for individuals and (b) foreign shareholders can distribute profits starting from 2025 and deadlines for foreign trade payments are relaxed. On July 4, 2025, the Argentine government issued Decree 450/25, initiating a 24-month transition period to reform and deregulate the country’s electricity market. The decree encourages free contracting between private 69 | The AES Corporation | June 30, 2026 Form 10-Q entities and fosters competition in electricity generation and commercialization. Subsequently, on October 20, 2025, the Ministry of Economy and the Secretariat of Energy issued Resolution 400/25, which became effective on November 1, 2025, and provides a new framework introducing more competitive price signals, decentralizing fuel management, and reducing subsidies. 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. 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 2025 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. 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. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns. 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 $19 million continues to be in technical default and is classified as current as of June 30, 2026. In 2022, a mediation commenced to resolve the PREPA Title III case. On March 19, 2025, the judge presiding over the case entered an order to permit the filing of an amended plan of adjustment and litigation of specific issues, including administrative expense claim by non-settling bondholders. The stay of plan confirmation and bondholder rights-related litigation was extended without a termination date, and the non-settling bondholders' motion to lift the stay was denied. The PROMESA Oversight Board filed an amended plan of adjustment and disclosure statement for PREPA on March 28, 2025. The mediation period was subsequently extended through October 31, 2026, reflecting the continuing efforts to resolve remaining matters under the Title III proceedings. Considering the information available as of the date hereof, management believes the carrying amount of our long-lived assets in Puerto Rico of $78 million is recoverable as of June 30, 2026. Impairments and Realizability Long-lived Assets and Held-for-Sale Disposal Group — During the six months ended June 30, 2026, the Company recognized asset impairment expense of $42 million, primarily related to the write-off of development projects that were determined to be no longer viable. See Note 16—Asset Impairment Expense included in Item 1.—Financial Statements of this Form 10-Q for further information. The net carrying amount of the held-for-sale disposal group assessed for impairment totaled $10 million at June 30, 2026. No impairment was recorded during the six months ended June 30, 2026 as a result of this assessment. Events or changes in circumstances that may necessitate recoverability tests and potential impairments of 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. Tax Asset Realizability — Certain AES Chilean businesses have recorded net deferred tax assets ("DTA") of $195 million relating primarily to net operating loss carryforwards, which are not subject to expiration. Their realization is dependent on generating sufficient taxable income. At this time, management believes it is more likely than not that all of the DTA will be realized; however, it could be reduced by way of valuation allowance in the near term if estimates of future taxable income are reduced. 70 | The AES Corporation | June 30, 2026 Form 10-Q Regulatory FERC, RTOs, and Interconnection Prioritization — FERC approved one-time queue jumping proposals in PJM, MISO, and Southwest Power Pool, Inc. over the course of the year. Limited additions to each RTO’s queue are not expected to materially impact the projects already in our backlog; however, they could create uncertainty around network upgrade costs and the timing of integration of future projects in each RTO’s queue. See Item 1A.—Risk Factors — Our development projects are subject to substantial uncertainties included in the 2025 Form 10-K for further details. AES Ohio Merger Application Submission — Subject to the terms of the Merger Agreement as described in Note 1—Financial Statement Presentation, the proposed AES Merger, AES, Parent, and Merger Sub are required to use reasonable best efforts to obtain all required regulatory approvals, including certain regulatory approvals from the PUCO. On April 10, 2026, AES Ohio submitted its required merger application to the PUCO. The PUCO is expected to review the application through its customary case process. AES Ohio Legislation and Three-Year Rate Plan (“TYRP”) — On April 30, 2025, the Ohio legislature passed new energy legislation (“House Bill 15”) that was signed by the Governor and became effective August 14, 2025. The legislation allows Ohio’s electric utilities to file three-year forecasted base distribution rate cases, which would replace electric security plans (“ESPs”) and incorporate associated recovery riders. Among other provisions, the legislation eliminates as of its effective date, the Legacy Generation Resource Rider (“LGR”), which previously allowed for recovery of net OVEC costs and revenues. Changes to the regulatory framework from this legislation, including the recovery of future net OVEC costs and revenues, could be material to our results of operations, financial condition, and cash flows. To comply with House Bill 15, AES Ohio filed an application with the PUCO on November 10, 2025 to establish a TYRP. This plan describes the investments necessary to strengthen and modernize AES Ohio's infrastructure and expand support for its customers. To enable these ongoing investments, the application also proposes rates for future electric distribution service in 2027, 2028, and 2029. On July 21, 2026, AES Ohio entered into an unopposed Stipulation and Recommendation (the “TYRP Settlement”) with intervening parties and the Staff of the PUCO. The TYRP Settlement provides for base distribution rates for 2027, 2028, and 2029, with annual true-up proceedings to forecasted amounts, and provides for a 9.5% return on equity, subject to annual performance metrics. The TYRP Settlement is subject to, and conditioned upon, approval by the PUCO. The evidentiary hearing was held on August 4, 2026, and AES Ohio anticipates a final order from the PUCO by the end of 2026. AES Ohio ESP Appeal — From November 1, 2017 through December 18, 2019, AES Ohio operated pursuant to an approved ESP plan, which was initially approved on October 20, 2017 (“ESP 3”). On December 18, 2019, the PUCO approved AES Ohio's Notice of Withdrawal of ESP 3 and reversion to its prior rate plan (“ESP 1”). Among other items, the PUCO Order approving the ESP 1 rate plan included reinstating the non-bypassable RSC Rider, which provided annual revenue of approximately $79 million. The OCC has appealed to the Ohio Supreme Court the PUCO’s decision approving the reversion to ESP 1, as well as argued for a refund of the RSC revenue dating back to August 2021. Oral arguments regarding this appeal were held on April 22, 2025, and a court decision is pending. AES Ohio Smart Grid Comprehensive Settlement — On October 23, 2020, AES Ohio entered into a Stipulation and Recommendation with the staff of the PUCO, various customers and organizations representing customers of AES Ohio and certain other parties with respect to, among other matters, AES Ohio's applications for (i) approval of AES Ohio's plan to modernize its distribution grid (“Smart Grid Phase 1”), (ii) findings that AES Ohio passed the SEET for 2018 and 2019, and (iii) findings that AES Ohio's ESP 1 satisfies the SEET and the more favorable in the aggregate (“MFA”) regulatory test. On June 16, 2021, the PUCO issued their opinion and order accepting the stipulation as filed. The OCC appealed the final PUCO order with respect to the 2018 and 2019 SEET to the Ohio Supreme Court on December 6, 2021. On August 22, 2025, the Ohio Supreme Court reversed the PUCO's opinion and order with respect to the methodology used by the PUCO to support its findings related to the 2018 and 2019 SEET, and remanded the case to the PUCO to conduct further analysis of the SEET for those years. The PUCO held an evidentiary hearing on this issue on October 28 and 29, 2025, and on July 8, 2026, the PUCO ordered AES Ohio to issue refunds totaling $11.1 million via a one-time bill credit. AES Indiana Rate Case Filing — On June 17, 2026, the IURC issued an order (the “2026 Base Rate Order”) approving in part the Stipulation and Settlement Agreement that AES Indiana entered into on October 15, 2025 with most parties in AES Indiana’s base rate case filing. Among other things, the 2026 Base Rate Order establishes proposed 2027 electric service base rates providing for a return on equity of 9.5%. In addition, the 2026 Base Rate Order includes a commitment to not implement additional base rate increases, following the 71 | The AES Corporation | June 30, 2026 Form 10-Q implementation of new base rates under the 2026 Base Rate Order, until at least January of 2030 and to not start a second TDSIC Plan before January of 2028. On July 7, 2026, the Office of Utility Consumer Counselor (“OUCC”) and Citizens Action Coalition (“CAC”) (parties to the regulatory rate review) each filed a petition for reconsideration and rehearing with the IURC. The IURC has until early September to rule on the request. On July 17, 2026, the OUCC also filed a notice of appeal with the Court of Appeals of Indiana. AES Indiana will implement new basic rates and charges authorized under the 2026 Base Rate Order in two phases. Phase one rates and charges became effective on July 27, 2026. Phase two rates and charges are anticipated to be effective in January of 2027. New basic rates and charges are subject to refund pending resolution of the regulatory petitions and legal appeal processes. AES Indiana Large Load Customer Project Filing — On April 22, 2026, AES Indiana filed a petition and case in chief seeking IURC approval related to certain generation resources and energy infrastructure investments required to serve increasing demand in AES Indiana's service territory, primarily driven by the anticipated demand for a new data center campus to be located in Monrovia, Indiana (the “Monrovia Project”). AES Indiana is also seeking approval of various accounting and ratemaking requests associated with the Monrovia Project. As part of developing this comprehensive plan, AES Indiana has incorporated certain protections for existing and future customers that ensure the costs of the generation resources and energy infrastructure upgrades required benefit all customers, are fairly allocated, and follow cost causation/beneficiary pays regulatory principles. The petition includes AES Indiana's plan to serve this increasing demand through the acquisition and development of additional generation resources. AES Indiana is seeking approval to acquire two development-stage renewables projects located in Indiana, as well as approval to develop and construct an energy storage project at its existing Hardy Hills renewable facility. The petition also includes AES Indiana's plan to develop and construct specific transmission network upgrades and enhancements required to serve the increasing demand, including seeking approval of a construction service agreement and an electric services agreement executed with the data center customer to provide high-voltage retail electric service to the new data center campus, which includes financial assurances, minimum demand commitments, and exit provisions as protections for existing customers. The IURC has set an evidentiary hearing to be held on August 5 and 6, 2026, and AES Indiana anticipates a final order from the IURC in the fourth quarter of 2026. 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 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. Environmental The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals), species and habitat protections, and certain air emissions, such as SO2, NOX, particulate matter, mercury, and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits, and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules, and regulations; and Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses included in the 2025 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 72 | The AES Corporation | June 30, 2026 Form 10-Q nonattainment, or interference with maintenance of, any NAAQS. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. On June 5, 2023, the EPA published a final Federal Implementation Plan (“FIP”) to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOX Ozone Season Group 3 trading program for 22 states, including Indiana and Maryland, and became effective during 2023 and includes enhancements to the revised Group 3 trading program. On June 27, 2024, the U.S. Supreme Court issued an order granting a stay of the EPA’s 2023 FIP pending resolution of legal challenges to the FIP. On November 6, 2024, the EPA published an Interim Final Rule in the Federal Register in response to the U.S. Supreme Court’s stay of its FIP addressing interstate transport for the 2015 Ozone NAAQs. The Interim Final Rule stays the effectiveness of the Good Neighbor FIP and revises the CSAPR regulations to continue application of the states’ respective trading programs. It is too early to determine the impact of this final rule, but it may result in the need to purchase additional allowances or make operational adjustments. While the Company's additional CSAPR compliance costs to date have been immaterial, the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time, but it could be material. New Source Performance Standards for Stationary Combustion Turbines — On December 13, 2024, the EPA published a proposed rule that would revise the NSPS regulating NOX and SO2 from certain new, modified, and reconstructed stationary combustion turbines ("CTs"). On January 15, 2026, the EPA issued a final rule establishing more stringent NOX emissions standards for certain CTs while retaining the existing SO2 standards. The final rule establishes NOX emissions limits based on selective catalytic reduction ("SCR") for new, large, high utilization combustion turbines. NOX emissions limits for other new, modified, and reconstructed CTs are based on combustion controls without SCR. The revised standards apply to affected sources that begin construction, modification, or reconstruction after December 13, 2024. The final rule is subject to litigation. We cannot predict the possible outcome or potential impacts of this matter at this time. Regional Haze Rule — The EPA's "Regional Haze Rule" established timelines for states to improve visibility in national parks and wilderness areas throughout the United States by establishing reasonable progress goals toward meeting a national goal of natural visibility conditions in Class I areas by the year 2064 through a series of state implementation plans ("SIPs"), which may result in additional emissions control requirements for electric generating units (“EGUs”). SIPs for the first planning period (through 2018) did not result in material impact to AES facilities. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. The deadline for submittal of the SIP covering the second planning period was July 31, 2021. On October 2, 2025, the EPA published an advanced notice of proposed rulemaking requesting public input on potential future changes to the Regional Haze Rule. On January 6, 2026, the EPA published a final rule extending the deadline for states to submit implementation plans for the third planning period from July 31, 2028 to July 31, 2031. To date, none of the states in which we operate have submitted plans that identify potential impacts to Company facilities. However, we cannot predict the possible outcome or potential impacts of this matter at this time. Mercury and Air Toxics Standard — In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective and AES facilities implemented measures to comply, as applicable. On May 7, 2024, the EPA published a final rule to revise MATS for coal and oil-fired electric generating units which lowers certain emissions limits and revises certain other aspects of MATS. The May 2024 MATS revision rule is subject to legal challenges. On June 17, 2025, the EPA published a proposed rule to repeal the majority of the May 7, 2024 final rule revising MATS. On February 24, 2026, the EPA issued a final rule repealing the majority of the May 7, 2024 MATS revision rule. The 2026 MATS repeal rule is subject to legal challenges. Further rulemakings and/or proceedings are possible. 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 — On May 9, 2024, the EPA published the final NSPS requiring carbon capture and sequestration for new and reconstructed baseload stationary combustion turbines, among other requirements. The EPA did not finalize revisions to the NSPS for newly constructed or reconstructed coal-fired electric utility steam generating units as proposed in 2018. Following prior rulemakings and litigation related to regulations for GHG emissions from EGUs, on May 9, 2024, the EPA published the final rule regulating GHGs from existing EGUs pursuant to Section 111(d) of the Clean 73 | The AES Corporation | June 30, 2026 Form 10-Q Air Act and effective on July 8, 2024. Existing EGUs are those that were constructed prior to January 8, 2014. Depending on various EGU-specific factors, the bases of emissions guidelines for natural gas-fired units include the use of uniform fuels and routine methods of operation and maintenance and the bases of emissions guidelines for coal-fired units include 40% natural gas co-firing or carbon capture and sequestration with 90% capture of CO2 depending on the date that coal operations cease. Specific standards for performance for EGUs will be established through a State Plan (or a Federal Plan if a state were to not submit an approvable plan). The May 2024 rule is subject to legal challenges. On June 17, 2025, the EPA published a proposed rule to repeal the May 9, 2024 final rules for new and existing EGUs in addition to 2015 greenhouse gas new source performance standards for certain new EGUs. In this proposed rule, the EPA also offered an alternative proposal to repeal a narrower set of greenhouse gas requirements which would include the repeal of requirements for existing EGUs and requirements based on carbon capture and sequestration for new EGUs. On September 16, 2025, the EPA published a proposed rule to remove certain greenhouse gas emissions reporting obligations from source categories, including electricity generation and electrical transmission and distribution equipment use. On February 18, 2026, the EPA published a final rule to rescind the 2009 greenhouse gas endangerment finding (which had concluded that greenhouse gases endanger public health and welfare). This rule is subject to legal challenges. It is too early to determine the potential impact of these rules, and the results of further proceedings and potential future greenhouse gas emissions regulations remain uncertain, but could be material. Following prior withdrawal and rejoining, on January 20, 2025, President Trump issued an Executive Order titled “Putting America First in International Environmental Agreements” directing the U.S. Ambassador to the United Nations to formally withdraw from the Paris Agreement. The international community has and continues to gather annually for the Conference to the Parties on the UN Framework Convention on Climate. As such, there is some uncertainty with respect to the impact of GHG rules. The NSPS for new EGUs will not require us to comply with an emissions standard until we construct a new electric generating unit. We do not have any planned major modifications of an existing source or plans to construct a new major source at this time which are expected to be subject to these regulations. Furthermore, the EPA, states, and other utilities are still evaluating potential impacts of the GHG regulations in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows, and financial condition. Due to the future uncertainty of these regulations and associated litigation, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with a new Section 111(d) Rule, should it be implemented in a prior or a substantially similar form, could be material. The GHG NSPS for new EGUs remains in effect at this time, and absent further action from the EPA that rescinds or substantively revises the NSPS, it could impact any Company plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition, or results of operations. Waste Management — On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and existing CCR landfills and CCR surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. The 2016 Water Infrastructure Improvements for the Nation Act ("WIN Act") includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. On May 28, 2026, the EPA reopened the comment period for the 2020 proposed rule. If a final federal CCR permit program is finalized before Indiana or Puerto Rico establishes a state-level CCR permit program, AES CCR units in those locations could eventually be required to apply for a federal CCR permit from the EPA. Following prior rulemaking development and comment periods, on December 18, 2025, the Indiana Environmental Rules Board adopted a final CCR rule that includes regulation of CCR through a state permitting program. IDEM submitted its State of Indiana Coal Combustion Residuals Permit Program Application to the EPA on June 26, 2026. The rule and permitting program would become effective upon approval by the EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made. On May 8, 2024, the EPA published final revisions to the CCR rule which expand the scope of CCR units regulated by the CCR Rule to include legacy surface impoundments, inactive surface impoundments, and CCR 74 | The AES Corporation | June 30, 2026 Form 10-Q management units. The May 8, 2024 revisions to the CCR Rule are currently subject to legal challenges. On February 10, 2026, the EPA published a final rule extending certain deadlines for coal combustion residual management units associated with its May 8, 2024 revisions to the CCR Rule. It is too early to determine the potential impact from these revisions to the CCR Rule. On April 13, 2026, the EPA published proposed revisions to the CCR Rule. The EPA is proposing modifications to the legacy and CCR management units provisions in the CCR Rule, the establishment of site-specific compliance pathways under federal or approved state CCR permits, and the revision of the definition of beneficial use of CCR. It is still too early to determine the potential impacts of these proposed revisions to our businesses. The CCR rule, current or proposed amendments to the federal CCR rule or state/territory CCR regulations, the results of groundwater monitoring data, or the outcome of CCR-related litigation could have a material impact on our business, financial condition, and results of operations. AES Indiana would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard. Cooling Water Intake — The Company's facilities are subject to a variety of rules governing water use and discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA effective in 2014 that seeks to protect fish and other aquatic organisms drawn into cooling water systems at power plants and other facilities. These standards require affected facilities to choose among seven best technology available (“BTA”) options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible that this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers) or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment. It is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. Certain AES Southland OTC units were required to be retired to provide interconnection capacity and/or emissions credits prior to startup of new (air cooled) generating units, and the remaining AES OTC generating units in California have been or will be shut down and permanently retired by the applicable OTC Policy compliance dates for the respective units. The California State Water Resources Board (“SWRCB”) OTC Policy currently requires the shutdown and permanent retirement of the remaining OTC generating units at AES Huntington Beach, LLC and AES Alamitos, LLC by December 31, 2026, as extended in support of grid reliability. This extension compliance date is contingent upon the facilities participating in the Strategic Reserve established by AB 205. Power plants are required to comply with the more stringent of state or federal requirements. At present, the California state requirements are more stringent and have earlier compliance dates than the federal EPA requirements, and are therefore applicable to the Company's California assets. The Company anticipates that compliance with CWA Section 316(b) regulations and associated costs could have a material impact on our consolidated financial condition or results of operations. Water Discharges — The concept of "Waters of the United States (“WOTUS”) defines the geographic reach and authority of the U.S. Army Corps of Engineers and the EPA (together, the “Agencies”) to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the appropriate standard for how to properly determine whether a wetland or stream that is not navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (“Decision”) in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional. On September 8, 2023, the Agencies published the “Revised Definition of ‘Waters of the United States’” rule. This final rule amendment conforms the definition to the definition adopted in the Decision. On March 12, 2025, the Agencies issued a joint guidance memorandum for implementing the “continuous surface connection” consistent with the Decision and related issues. On March 24, 2025, the Agencies published notice outlining a process to gather recommendations for implementation of WOTUS. On November 20, 2025, the Agencies proposed revisions to align the definition of WOTUS with the Decision to clarify federal jurisdiction under CWA. It is too early to determine whether the outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over WOTUS may have a material impact on our business, financial condition, or results of operations. 75 | The AES Corporation | June 30, 2026 Form 10-Q In November 2015, the EPA published its final Effluent Limitation Guideline (“ELG”) rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. In 2020, the EPA issued a final rule, known as the 2020 Reconsideration Rule, revising certain aspects of the 2015 ELG rule. 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, 2024, the EPA published a final rule revising the 2020 Reconsideration 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. On December 31, 2025, the EPA published a final rule that extended ELG Rule compliance deadlines. On May 18, 2026, the EPA published a proposed rule related to unmanaged combustion residual leachate. The proposed rule would revise certain best available technology limits in the 2024 ELG Rule and would extend the compliance deadline from December 31, 2029 to December 31, 2034. It is too early to determine whether any outcome of litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition, and results of operations. On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of "functional equivalent" are ongoing in various jurisdictions. On November 27, 2023, the EPA issued a draft guidance addressing how the Supreme Court decision would be applied to the NPDES permit program as it relates to functional equivalent discharge. However, in February 2025, the EPA pulled back the guidance before it cleared the Office of Management and Budget. It is too early to determine whether the Supreme Court decision or the result of litigation to "functional equivalent" may have a material impact on our business, financial condition, or results of operations. U.S. Executive Actions Affecting Environmental Regulations — On January 20, 2025, President Trump issued an Executive Order titled “Unleashing American Energy” directing Agencies to, among other tasks, review regulations issued under the prior Administration to determine whether they should be suspended, revised, or rescinded. The Trump Administration also issued a Memorandum titled “Regulatory Freeze Pending Review” directing Agencies to refrain from proposing or issuing any rules until the Trump Administration has reviewed and approved those rules. In accordance with these and other Trump Administration Executive Orders, on March 12, 2025, the EPA released a list of environmental regulations that will be targeted for reconsideration and other deregulatory action. These and other actions, including other Executive Orders and directives from the Trump Administration, may have an impact on regulations and permitting processes that may affect our business, financial condition, or results of operations. Capital Resources and Liquidity Overview As of June 30, 2026, the Company had unrestricted cash and cash equivalents of $1.8 billion, of which $43 million was held at the Parent Company and qualified holding companies. The Company had restricted cash and debt service reserves of $583 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $25.2 billion and $6.1 billion, respectively. Of the $3.2 billion of our current non-recourse debt, $3.1 billion was presented as such because it is due in the next twelve months and $19 million relates to debt considered in default. These defaults are not payment defaults but are instead technical defaults triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents. See Note 8—Obligations in Item 1.—Financial Statements of this Form 10-Q for additional detail. As of June 30, 2026, the Company also had $826 million outstanding related to supplier financing arrangements. We expect current maturities of non-recourse debt, recourse debt, and amounts due under supplier financing arrangements to be repaid from net cash provided by operating activities of the subsidiary to which the liability relates, through opportunistic refinancing activity, or some combination thereof. We have $300 million in recourse debt which matures within the next twelve months. Furthermore, we have $684 million due under supplier financing arrangements that have a guarantee, $103 million guaranteed by the Parent Company and $581 million guaranteed by subsidiaries. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions, or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other 76 | The AES Corporation | June 30, 2026 Form 10-Q factors. The amounts involved in any such repurchases may be material. We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies, and related assets. Our non-recourse financing is designed to limit cross-default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks. Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company does not have any material unhedged exposure to variable interest rate debt. Additionally, commercial paper issuances are short-term in nature and subject the Parent Company to interest rate risk at the time of refinancing the paper. On a consolidated basis, of the Company’s $31.7 billion of total gross debt outstanding as of June 30, 2026, approximately $9.9 billion accrues interest at variable rates, the majority of which is related to project financing. The Company actively hedges its current and expected variable rate exposure through a combination of currently effective and forward starting interest rate swaps. As of June 30, 2026, the total maximum outstanding amount of hedges protecting the Company against current and expected variable rate exposure on project financing was $9.5 billion. These hedges generally provide economic protection through the entire expected life of the projects, regardless of the type of debt issued to finance construction or refinance the projects in the future. In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction, or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets, and/or the proceeds from our issuances of debt, common stock, and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial and performance-related guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment, or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. As of June 30, 2026, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $4.4 billion in aggregate. This amount excludes arrangements that relate solely to the Company's own future performance, as well as those that are collateralized by letters of credit and other obligations discussed below. Some counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. As of June 30, 2026, we had $159 million in letters of credit under bilateral agreements, $174 million in letters of credit outstanding provided under our unsecured credit facilities, and $9 million in letters of credit outstanding provided under our revolving credit facilities. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations. Additionally, in connection with certain project financings, some of the Company's subsidiaries have expressly undertaken limited obligations and commitments. These contingent contractual obligations are issued at the subsidiary level and are non-recourse to the Parent Company. As of June 30, 2026, the consolidated maximum undiscounted potential exposure to guarantees, letters of credit, and surety bonds issued by our subsidiaries was $5.4 billion, including $3.3 billion of guarantees and commitments, $2.1 billion of letters of credit outstanding, and $73 million of surety bonds. 77 | The AES Corporation | June 30, 2026 Form 10-Q We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct, or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary. Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness, or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses. Long-Term Receivables As of June 30, 2026, the Company had approximately $119 million of gross accounts receivable classified as Other noncurrent assets. These noncurrent receivables mostly consist of accounts receivable in the U.S. and Chile that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond June 30, 2027, or one year from the latest balance sheet date. Noncurrent receivables in the U.S. pertain to the sale of the Redondo Beach land. Noncurrent receivables in Chile pertain primarily to payment deferrals granted to mining customers as part of our green blend agreements. See Note 5—Financing Receivables in Item 1.—Financial Statements of this Form 10-Q for further information. As of June 30, 2026, the Company had an $806 million loan receivable related to the Mong Duong facility in Vietnam, which was constructed under a BOT contract. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25-year term of the plant’s PPA. Of the loan receivable balance, $96 million was classified in Other current assets and $710 million was classified in Loan receivable on the Condensed Consolidated Balance Sheets. See Note 5—Financing Receivables and Note 14—Revenue in Item 1.—Financial Statements of this Form 10-Q for further information. Cash Sources and Uses The primary sources of cash for the Company in the six months ended June 30, 2026 were debt financings, cash flows from operating activities, and purchases under supplier financing arrangements. The primary uses of cash in the six months ended June 30, 2026 were repayments of debt, capital expenditures, distributions to noncontrolling interests, and repayments of obligations under supplier financing arrangements. The primary sources of cash for the Company in the six months ended June 30, 2025 were debt financings, cash flows from operating activities, sales to noncontrolling interests, purchases under supplier financing arrangements, and issuance of preferred shares in subsidiaries. The primary uses of cash in the six months ended June 30, 2025 were repayments of debt, capital expenditures, and repayments of obligations under supplier financing arrangements. 78 | The AES Corporation | June 30, 2026 Form 10-Q A summary of cash-based activities is as follows (in millions): Six Months Ended June 30, Cash Sources: 2026 2025 Borrowings under the revolving credit facilities $ 2,826 $ 2,128 Net cash provided by operating activities 2,247 1,521 Issuance of recourse debt 1,800 800 Issuance of non-recourse debt 1,424 2,332 Purchases under supplier financing arrangements 669 567 Sales to noncontrolling interests 306 1,138 Issuance of preferred shares in subsidiaries 282 452 Proceeds from the sale of business interests, net of cash and restricted cash sold 233 5 Sale of short-term investments 129 52 Other 157 436 Total Cash Sources $ 10,073 $ 9,431 Cash Uses: Capital expenditures (1) $ (3,409) $ (2,586) Repayments under revolving credit facilities (1,982) (2,398) Repayments of recourse debt (1,300) (774) Distributions to noncontrolling interests (1,238) (338) Repayments of non-recourse debt (720) (1,490) Repayments of obligations under supplier financing arrangements (448) (862) Dividends paid on AES common stock (251) (250) Purchase of emissions allowances (223) (234) Other (281) (337) Total Cash Uses $ (9,852) $ (9,269) Net increase in Cash, Cash Equivalents, and Restricted Cash $ 221 $ 162 _____________________________ (1)Includes interest capitalized on development and construction of $227 million and $242 million for the six months ended June 30, 2026 and 2025, respectively. Of the total capitalized, $217 million and $232 million, respectively, are related to recourse and non-recourse debt interest payments. The remaining capitalized interest is primarily related to supplier financing arrangements. Consolidated Cash Flows The following table reflects the changes in operating, investing, and financing cash flows for the comparative six-month period (in millions): Six Months Ended June 30, Cash flows provided by (used in): 2026 2025 $ Change Operating activities $ 2,247 $ 1,521 $ 726 Investing activities (3,263) (2,882) (381) Financing activities 1,241 1,462 (221) Operating Activities Net cash provided by operating activities increased $726 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025. Operating Cash Flows (in millions) (1)The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Condensed Consolidated Statements of Cash Flows in Item 1.—Financial Statements of this Form 10-Q. (2)The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Condensed Consolidated Statements of Cash Flows in Item 1.—Financial Statements of this Form 10-Q. 79 | The AES Corporation | June 30, 2026 Form 10-Q •Adjusted net income increased $776 million, primarily due to higher margins at the Renewables, Utilities, and Energy Infrastructure SBUs, and increased transfers of U.S. investment tax credits. •Change in working capital decreased $50 million, primarily due to an increase in accounts receivable due to higher billings and the timing of collections, an increase in other current assets in El Salvador related to an increase in regulatory assets, and a decrease in income tax payables due to the timing of tax payments, partially offset by a decrease in other current assets due to the timing of collection of tax credit transfer proceeds. Investing Activities Net cash used in investing activities increased $381 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025. Investing Cash Flows (in millions) •Cash proceeds from sales of business interests increased $228 million, primarily due to proceeds from the partial sale of our ownership interests in Fluence. •Cash provided by short-term investing activities increased $112 million, primarily due to the timing of deposits at AGIC. •Cash paid for acquisitions of business interests decreased $91 million, primarily due to the prior year acquisition of Crossvine for $78 million and higher net acquisitions in the prior year of $33 million for various businesses at AES Clean Energy Development. •Capital expenditures increased $823 million, discussed further below. Capital Expenditures (in millions) (1)Growth expenditures generally include expenditures related to development projects in construction, expenditures that increase capacity of a facility beyond the original design, and investments in general load growth or system modernization. (2)Maintenance expenditures generally include expenditures that are necessary to maintain regular operations or net maximum capacity of a facility. •Growth expenditures increased $799 million, primarily due to an increase in expenditures for U.S. and Chile renewables projects compared to the prior year and an increase in transmission and distribution project investments at our U.S. utilities compared to the prior year. 80 | The AES Corporation | June 30, 2026 Form 10-Q •Maintenance expenditures increased $24 million, primarily due to the timing of maintenance at AES Ohio. Financing Activities Net cash provided by financing activities decreased $221 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025. Financing Cash Flows (in millions) See Notes 1—Financial Statement Presentation, 8—Obligations, 11—Redeemable Stock of Subsidiaries, and 12—Equity in Item 1.—Financial Statements of this Form 10-Q for more information regarding significant transactions. •The $900 million impact from distributions to noncontrolling interests is mainly due to $633 million of higher distributions of proceeds from the transfer of U.S. investment tax credits to tax equity partners in the current year and a $220 million distribution at AES Puerto Rico Solar. •The $832 million impact from sales to noncontrolling interests is primarily due to $540 million in proceeds from the sale of ownership in AES Ohio in the prior year and $277 million higher proceeds from selldowns in various projects to tax equity investors in the prior year. •The $300 million impact from the Parent Company revolver is primarily due to net repayments in the current year. •The $170 million impact from issuance of preferred shares in subsidiaries is primarily due to proceeds from the issuance of preferred shares in AES Global Insurance in the prior year, partially offset by proceeds from the issuance of preferred shares in Marahu and Desarrollos Renovables in the current year. •The $146 million impact from the commercial paper program is due to higher net repayments in the current year and higher net borrowings in the prior year. •The $1.4 billion impact from non-recourse revolvers is primarily due to higher net borrowings in the current year and higher net repayments in the prior year at our Renewables and Utilities SBUs. •The $516 million impact from supplier financing arrangements is primarily due to higher borrowings in the current year and higher repayments in the prior year at the Renewables SBU, partially offset by higher repayments in the current year at the Energy Infrastructure SBU. •The $474 million impact from recourse debt is due to issuances at the Parent Company of $1.8 billion in the current year and repayments of $774 million in the prior year, partially offset by repayments of $1.3 billion in the current year and issuance of $800 million senior notes in the prior year. Parent Company Liquidity The following discussion is included as a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity, as outlined below, is a non-GAAP measure and should not be construed as an alternative to Cash and cash equivalents, which is determined in accordance with GAAP. Parent Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are dividends and other distributions from our subsidiaries, including refinancing proceeds; proceeds from debt and equity financings at the Parent Company level, including availability under our revolving credit facilities and commercial 81 | The AES Corporation | June 30, 2026 Form 10-Q paper program; and proceeds from asset sales. The Parent Company credit facilities and commercial paper program are generally used for short-term cash needs to bridge the timing of distributions from subsidiaries. Cash requirements at the Parent Company level are primarily to fund interest and principal repayments of debt, construction commitments, other equity commitments, acquisitions, taxes, Parent Company overhead and development costs, and dividends on common stock. The Company defines Parent Company Liquidity as cash available to the Parent Company, including cash at qualified holding companies, plus available borrowings under our existing credit facilities and commercial paper program. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable GAAP financial measure, Cash and cash equivalents, at the periods indicated as follows (in millions): June 30, 2026 December 31, 2025 Consolidated cash and cash equivalents $ 1,800 $ 1,382 Less: Cash and cash equivalents at subsidiaries (1,757) (1,372) Parent Company and qualified holding companies’ cash and cash equivalents 43 10 Commitments under the Parent Company credit facilities 1,800 1,800 Less: Letters of credit under the credit facilities (9) (50) Less: Borrowings under the credit facilities — (300) Less: Borrowings under the commercial paper program — (79) Borrowings available under the Parent Company credit facilities 1,791 1,371 Total Parent Company Liquidity $ 1,834 $ 1,381 The Parent Company paid dividends of $0.17595 per outstanding share to its common stockholders during each of the first and second quarters of 2026 for dividends declared in December 2025 and February 2026. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance that we will continue to pay dividends, or if continued, the amount of such dividends. Recourse Debt Our total recourse debt was $6.1 billion and $6 billion as of June 30, 2026 and December 31, 2025, respectively. See Note 8—Obligations in Item 1.—Financial Statements of this Form 10-Q and Note 12—Obligations in Item 8.—Financial Statements and Supplementary Data of our 2025 Form 10-K for additional detail. We believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future. This belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions, and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our revolving credit facility and commercial paper program. See Item 1A.—Risk Factors—The AES Corporation’s ability to make payments on its outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries of the Company’s 2025 Form 10-K for additional information. Various debt instruments at the Parent Company level, including our revolving credit facility and commercial paper program, contain certain restrictive covenants. The covenants provide for, among other items, limitations on other indebtedness, liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions; restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements; maintenance of certain financial ratios; and financial and other reporting requirements. As of June 30, 2026, we were in compliance with these covenants at the Parent Company level. Non-Recourse Debt While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation: •reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default; •triggering our obligation to make payments under any financial guarantee, letter of credit, or other credit support 82 | The AES Corporation | June 30, 2026 Form 10-Q we have provided to or on behalf of such subsidiary; •causing us to record a loss in the event the lender forecloses on the assets; and •triggering defaults in our outstanding debt at the Parent Company. For example, our revolving credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy-related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries. Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying Condensed Consolidated Balance Sheets amounts to $3.2 billion. The portion of current debt related to such defaults was $19 million at June 30, 2026, all of which was non-recourse debt related to two subsidiaries: AES Ilumina and a project entity at AES Clean Energy Development. These defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants or other conditions contained in the non-recourse debt documents. See Note 8—Obligations in Item 1.—Financial Statements of this Form 10-Q for additional detail. None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under the Parent Company’s debt agreements as of June 30, 2026, in order for such defaults to trigger an event of default or permit acceleration under the Parent Company’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Parent Company’s revolving credit agreement as any business that contributed 20% or more of the Parent Company’s total cash distributions from businesses for the four most recently ended fiscal quarters. As of June 30, 2026, none of the defaults listed above resulted in a cross-default under the recourse debt of the Parent Company. Furthermore, none of the non-recourse debt in default listed above is guaranteed by the Parent Company. Critical Accounting Policies and Estimates The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1—General and Summary of Significant Accounting Policies of our 2025 Form 10-K. The Company’s critical accounting estimates are described in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2025 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, if different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that these remain as critical accounting policies as of and for the six months ended June 30, 2026.