Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2024 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, those 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 2024 Form 10-K and subsequent filings with the SEC.

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 revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates 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), Utilities (AES Indiana, AES Ohio, and AES El Salvador), Energy Infrastructure (natural gas, LNG, coal, pet coke, diesel, and oil), and New Energy Technologies (investments in Fluence, Uplight, Maximo, and other initiatives). Prior to the first quarter of 2025, our businesses in Chile (which have a mix of generation sources, including renewables, that were pooled to service our existing PPAs) were reported in the Energy Infrastructure SBU. After the sale or disconnection of a significant portion of AES Andes’ coal plants and the expiration of its coal-indexed contracts with regulated customers at the end of 2024, the results of our businesses in Chile, excluding the two remaining coal plants, are now reported as part of the Renewables SBU. The results of the two remaining coal plants in Chile, Angamos and Cochrane, remain within the Energy Infrastructure SBU. For additional information regarding our business, see Item 1.—Business of our 2024 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, distribute, transmit, 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.

Executive Summary

Compared with last year, first quarter net income decreased $351 million, from net income of $278 million to a net loss of $73 million. This decrease is the result of higher prior year revenues from the monetization of the Warrior Run coal plant PPA, one-time costs due to organizational restructuring, and a gain in the prior year on dilution of our interest in Uplight; partially offset by higher contributions from the Utilities and Renewables SBUs.

Adjusted EBITDA, a non-GAAP measure, decreased $49 million, from $640 million to $591 million, driven by lower contributions from the Energy Infrastructure SBU primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA. This was partially offset by higher margins at the Utilities SBU, higher revenues from renewables projects placed in service, and better hydrology.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, decreased $91 million, from $868 million to $777

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million primarily due to the drivers above, as well as lower realized tax attributes driven by timing of tax attribute recognition.

Compared with last year, first quarter diluted earnings per share from continuing operations decreased $0.53, from $0.60 to $0.07. This decrease is mainly driven by lower earnings at the Energy Infrastructure SBU primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA, lower realized tax attributes, a gain in the prior year on dilution of our interest in Uplight, and one-time costs due to organizational restructuring. This was partially offset by higher contributions at the Utilities SBU due to higher margins and realized tax attributes related to the Pike County energy storage project.

Adjusted EPS, a non-GAAP measure, decreased $0.23 from $0.50 to $0.27, mainly driven by lower realized tax attributes due to timing of tax attribute recognition, and lower contributions at the Energy Infrastructure SBU primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA, partially offset by higher contributions at the Utilities SBU.

36 | The AES Corporation | March 31, 2025 Form 10-Q

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(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 2024.

37 | The AES Corporation | March 31, 2025 Form 10-Q

Overview of Strategic Performance

AES is leading the industry's transition to clean energy by investing in renewables, utilities, and technology businesses.

  • Our PPA backlog, which consists of projects with signed contracts, but which are not yet operational, is 11.7 GW, including 5.3 GW under construction. Since our fourth quarter 2024 earnings call in February 2025, we:

◦Completed the construction of 643 MW of energy storage and solar, and expect to add a total of 3.2 GW to our operating portfolio by year-end 2025; and

◦Signed or were awarded new long-term PPAs for 443 MW of solar and energy storage.

  • Received final regulatory approval for the 170 MW Crossvine solar-plus-storage project at AES Indiana, which is expected to come online in 2027.

  • With the sale of a minority stake in our global insurance company, AGIC, for $450 million, achieved full year 2025 asset sale proceeds target of $400 to $500 million.

  • To fund the substantial growth at AES Ohio, closed on the sale of an approximate 30% indirect equity interest to a wholly-owned subsidiary of CDPQ, with subsequent upgrade in credit ratings at AES Ohio.

Review of Consolidated Results of Operations (Unaudited)

Three Months Ended March 31,
(in millions, except per share amounts)20252024$ change% change
Revenue:
Renewables SBU$666$643$234%
Utilities SBU1,00987313616%
Energy Infrastructure SBU1,3201,609(289)-18%
New Energy Technologies SBU————%
Corporate and Other363339%
Eliminations(105)(73)(32)-44%
Total Revenue2,9263,085(159)-5%
Operating Margin:
Renewables SBU73631016%
Utilities SBU1551203529%
Energy Infrastructure SBU189394(205)-52%
New Energy Technologies SBU—(2)2-100%
Corporate and Other5865(7)-11%
Eliminations(34)(21)(13)-62%
Total Operating Margin441619(178)-29%
General and administrative expenses(77)(75)(2)3%
Interest expense(342)(357)15-4%
Interest income69105(36)-34%
Loss on extinguishment of debt(8)(1)(7)NM
Other expense(52)(38)(14)37%
Other income735(28)-80%
Gain (loss) on disposal and sale of business interests(1)43(44)NM
Asset impairment expense(49)(46)(3)7%
Foreign currency transaction losses(10)(8)(2)25%
Income tax benefit (expense)(17)16(33)NM
Net equity in losses of affiliates(34)(15)(19)NM
NET INCOME (LOSS)(73)278(351)NM
Less: Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries119154(35)-23%
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION$46$432$(386)-89%
Net cash provided by operating activities$545$287$25890%

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

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include electricity and fuel purchases, operations and maintenance 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 associated with the purchase of electricity or fuel.

Operating margin is defined as revenue less cost of sales.

Consolidated Revenue and Operating Margin

Three Months Ended March 31, 2025

Revenue

(in millions)

1066

Consolidated Revenue — Revenue decreased $159 million, or 5%, for the three months ended March 31, 2025, compared to the three months ended March 31, 2024, driven by:

  • $289 million at Energy Infrastructure driven by $239 million of prior year revenue related to the AES Andes portfolio, which is reported in the Renewables SBU beginning in 2025 following the sale and expiration of certain coal-related assets and contracts; $96 million of prior year revenues from the monetization of the Warrior Run coal plant PPA, $91 million due to prior year unrealized and realized derivative gains, and $23 million due to the impact of the selldown of Amman East and IPP4 in Jordan; partially offset by $82 million higher CO2 purchases passed through due to higher production, $32 million higher gas prices and transportation costs passed through to the offtaker, and $30 million higher generation due to dispatch and tariff adjustment in Argentina.

This unfavorable impact was partially offset by increases of:

  • $136 million at Utilities mainly driven by a $111 million increase in transmission, distribution, and rider revenues mainly due to higher rates, and $34 million due to higher net retail demand mainly driven by favorable weather; partially offset by $20 million of lower Fuel Adjustment Charge rider revenue; and

  • $23 million at Renewables mainly driven by a $203 million increase due to the results of AES Andes moving to Renewables in 2025 as described above, net of a current year decrease in regulated contract sales, and $50 million due to new projects in service; partially offset by $170 million impact from the sale of AES Brasil and $50 million net lower spot sales and prices, mainly at Colombia.

Operating Margin

(in millions)

1907

Consolidated Operating Margin — Operating margin decreased $178 million, or 29%, for the three months

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ended March 31, 2025, compared to the three months ended March 31, 2024, driven by:

  • $205 million at Energy Infrastructure mainly driven by $96 million higher prior year revenues from the monetization of the Warrior Run coal plant PPA, $71 million due to prior year unrealized derivative gains as part of our commercial hedging strategy, $22 million of prior year operating margin related to the AES Andes portfolio, which is reported in the Renewables SBU beginning in 2025 following the sale and expiration of certain coal-related assets and contracts, and $17 million of one-time costs due to restructuring; and

  • $20 million at Corporate, Other and Eliminations mainly driven by higher people and IT costs, including allocation of costs to the businesses.

These unfavorable impacts were partially offset by increases of:

  • $35 million at Utilities primarily driven by $43 million due to higher retail rates as a result of the 2024 Base Rate Order, including the impact of certain riders now included in the base rate, $20 million due to higher demand primarily from the impact of weather, and a $13 million increase in transmission and rider revenues; partially offset by a $13 million increase in depreciation expense from additional assets placed in service, an $8 million decrease due to the impact of planned outages, $8 million higher expected credit losses, and $7 million higher property taxes; and

  • $10 million at Renewables mainly driven by a $36 million increase related to higher generation in Panama as a result of better hydrological conditions, $35 million positive impact from new businesses, and $22 million impact of the results of AES Andes moving to Renewables in 2025, as described above. These positive impacts were partially offset by a $36 million increase in fixed costs primarily related to an accelerated growth plan, a $32 million impact from the sale of AES Brasil, and $16 million of one-time costs due to restructuring.

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 $2 million, or 3%, to $77 million for the three months ended March 31, 2025, compared to $75 million for the three months ended March 31, 2024, mainly due to $8 million of one-time restructuring costs, partially offset by $3 million lower professional fees and $2 million lower other people costs.

Interest expense

Interest expense decreased $15 million, or 4%, to $342 million for the three months ended March 31, 2025, compared to $357 million for the three months ended March 31, 2024. This decrease is primarily due to a $61 million impact from the sale of AES Brasil in October 2024; partially offset by increased borrowings at the Renewables SBU and lower capitalized interest.

Interest capitalized during development and construction decreased $41 million to $116 million for the three months ended March 31, 2025, compared to $157 million for the three months ended March 31, 2024, primarily due to fewer projects in development at the Renewables SBU.

Interest income

Interest income decreased $36 million, or 34%, to $69 million for the three months ended March 31, 2025, compared to $105 million for the three months ended March 31, 2024, primarily due to a $24 million decrease at the Energy Infrastructure SBU primarily due to lower short-term investments at lower rates, and a $13 million impact from the sale of AES Brasil in October 2024.

Other income and expense

Other income decreased $28 million, or 80%, to $7 million for the three months ended March 31, 2025, compared to $35 million for the three months ended March 31, 2024, mainly due to a $10 million decrease in gains on remeasurement of contingent consideration at AES Clean Energy, and the prior year impacts of a $5 million gain on commencement of a sales-type lease on land, $5 million in insurance proceeds primarily related to property damage at AES Andes, and a $5 million gain on contract termination.

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Other expense increased $14 million, or 37%, to $52 million for the three months ended March 31, 2025, compared to $38 million for the three months ended March 31, 2024, mainly due to a $34 million increase in losses on remeasurement of contingent consideration primarily on projects acquired at AES Clean Energy and $9 million in losses on commencement of sales-type leases at AES Renewable Holdings; partially offset by a $19 million loss recognized in the prior year related to legal expenses and other direct costs associated with the troubled debt restructuring at AES Puerto Rico, and a $6 million valuation allowance recorded in the prior year on receivables classified as held-for-sale at Warrior Run.

See Note 15—Other Income and Expense included in Item 1.—Financial Statements of this Form 10-Q for further information.

Gain (loss) on disposal and sale of business interests

Loss on disposal and sale of business interests was $1 million for the three months ended March 31, 2025 compared to a gain of $43 million for three months ended March 31, 2024. This was primarily due to a $52 million gain in the prior year on dilution of AES’ ownership interest in Uplight as a result of the AutoGrid acquisition, partially offset by a $10 million loss in the prior year on the selldown of Amman East and IPP4 in Jordan, which are now accounted for as equity method investments.

See Note 7—Investments in and Advances to Affiliates and Note 18—Held-for-Sale and Dispositions for further information.

Asset impairment expense

Asset impairment expense increased $3 million, or 7%, to $49 million for the three months ended March 31, 2025, compared to $46 million for the three months ended March 31, 2024. This increase was due to higher impairment expense of $24 million at AES Clean Energy Development related to the write-off of capitalized development costs for projects that were determined to be no longer viable. This was partially offset by lower impairment expense of $20 million associated with the held-for-sale classification of Mong Duong.

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 March 31,
(in millions)20252024
Chile$(11)$(6)
Other1(2)
Total (1)$(10)$(8)

(1)Includes losses of $3 million and gains of $18 million on foreign currency derivative contracts for the three months ended March 31, 2025 and 2024, respectively.

The Company recognized net foreign currency transaction losses of $10 million for the three months ended March 31, 2025, primarily driven by unrealized losses due to depreciation of the Chilean peso.

The Company recognized net foreign currency transaction losses of $8 million for the three months ended March 31, 2024, primarily driven by realized losses on receivables denominated in the Chilean peso.

Income tax benefit (expense)

Income tax expense was $17 million for the three months ended March 31, 2025, compared to income tax benefit of $16 million for the three months ended March 31, 2024. The Company’s effective tax rates were (77)% and (6)% for the three months ended March 31, 2025 and 2024, respectively. The current quarter effective tax rate was impacted by tax expense resulting from allocations of losses to tax equity investors on renewables projects, as well as the impacts associated with ITCs.

The prior year effective tax rate was benefited by the restructuring of a foreign holding company, as well as the impacts associated with ITCs. Further, the prior year effective tax rate was impacted by 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 GILTI rules and incremental foreign taxation under Pillar 2. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions

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could impact our periodic effective tax rate.

Net equity in losses of affiliates

Net equity in losses of affiliates increased $19 million to $34 million for the three months ended March 31, 2025, compared to $15 million for the three months ended March 31, 2024. This increase was primarily driven by lower earnings from sPower of $14 million, mainly due to lower earnings from renewables projects that came online; and a $9 million decrease in earnings from Fluence driven by a decrease in the volume of BESS products fulfilled due to timing of customer schedules, higher sales and marketing expenses, and foreign currency losses.

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 $35 million to $119 million for the three months ended March 31, 2025, compared to $154 million for the three months ended March 31, 2024. This decrease was primarily due to lower allocation of losses to tax equity investors on renewables projects placed in service of $35 million.

Net income attributable to The AES Corporation

Net income attributable to The AES Corporation decreased $386 million to $46 million for the three months ended March 31, 2025, compared to $432 million for the three months ended March 31, 2024. This decrease was primarily due to:

  • Lower margins from the Energy Infrastructure SBU of $193 million, excluding one-time restructuring costs, primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA and prior year unrealized gains on power swaps;

  • Prior year gain on dilution of our interest in Uplight of $52 million;

  • One-time restructuring costs of $46 million;

  • Higher interest expense and lower interest income in the current year of $36 million;

  • Lower contributions from renewables projects placed in service in the current year of $35 million; and

  • Higher net equity in losses of affiliates of $18 million, primarily related to lower earnings from renewables projects that came online at sPower.

These decreases were partially offset by higher margins from the Utilities SBU of $28 million, excluding one-time restructuring costs, primarily due to higher rates as a result of the 2024 Base Rate Order at AES Indiana and higher demand due to weather.

SBU Performance Analysis

Non-GAAP Measures

EBITDA, Adjusted EBITDA, Adjusted EBITDA with Tax Attributes, Adjusted PTC, and Adjusted EPS 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.

During the first quarter of 2025, the Company updated the definitions of Adjusted EBITDA, Adjusted PTC, and Adjusted EPS 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.

For the year ended December 31, 2024, the Company updated the definitions of EBITDA and Adjusted EBITDA to include accretion of AROs in the depreciation and amortization add-back. We believe excluding accretion of AROs from these metrics better reflects the underlying business performance of the Company and is aligned with the metrics of our industry peers. For comparability and consistency, all prior period EBITDA and Adjusted EBITDA measures have been recast to conform to the current presentation. The impact of this update resulted in an

42 | The AES Corporation | March 31, 2025 Form 10-Q

increase to Adjusted EBITDA of $5 million for the three months ended March 31, 2024.

During the first quarter of 2024, the Company updated the definitions of Adjusted EBITDA, Adjusted PTC, and Adjusted EPS add-back (a) unrealized gains or losses related to derivative transactions and equity securities to include financial assets and liabilities measured using the fair value option, and updated add-back (e) gains, losses, and costs due to the early retirement of debt to include troubled debt restructuring. We believe excluding these gains or losses better reflects the underlying business performance of the Company. The Company also removed the adjustment for net gains at Angamos, one of our businesses in the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. As this adjustment was specific to certain contract terminations that occurred in 2020, we believe removing this adjustment from our non-GAAP definitions provides simplification and clarity for our investors. There were no such impacts in 2024.

EBITDA, Adjusted EBITDA and Adjusted EBITDA with Tax Attributes

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, amortization, and accretion of AROs 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; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts.

In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted EBITDA includes the other components of our Consolidated Statement 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.

We further define Adjusted EBITDA with Tax Attributes as Adjusted EBITDA, adding back the pre-tax 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.

The GAAP measure most comparable to EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes is Net income. We believe that EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes 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, or implement restructuring initiatives, 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, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes should not be construed as alternatives to Net income, which is determined in accordance with GAAP.

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Three Months Ended March 31,
Reconciliation of Adjusted EBITDA and Adjusted EBITDA with Tax Attributes (in millions)20252024
Net income$(73)$278
Income tax expense17(16)
Interest expense342357
Interest income(69)(105)
Depreciation, amortization, and accretion of AROs337318
EBITDA$554$832
Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1)(134)(164)
Less: Income tax expense (benefit), interest expense (income) and depreciation, amortization, and accretion of AROs from equity affiliates3634
Interest income recognized under service concession arrangements1517
Unrealized derivatives, equity securities, and financial assets and liabilities gains(1)(85)
Unrealized foreign currency gains(7)(9)
Disposition/acquisition losses (gains)41(43)
Impairment losses3326
Loss on extinguishment of debt and troubled debt restructuring832
Restructuring costs46—
Adjusted EBITDA (1)$591$640
Tax attributes186228
Adjusted EBITDA with Tax Attributes (2)$777$868

(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.

(2) Adjusted EBITDA with Tax Attributes includes the impact of the share of the ITCs, PTCs, and depreciation deductions allocated to tax equity investors under the HLBV accounting method and recognized as Net loss (income) attributable to noncontrolling interests and redeemable stock of subsidiaries on the Condensed Consolidated Statements of Operations. It also includes the tax benefit recorded from tax credits retained or transferred to third parties. The tax attributes are related to the Renewables and Utilities SBUs.

5439

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; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts. 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

44 | The AES Corporation | March 31, 2025 Form 10-Q

the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our Consolidated Statement 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, strategic decisions to dispose of or acquire business interests, retire debt, or implement restructuring initiatives, 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.

Three Months Ended March 31,
Reconciliation of Adjusted PTC (in millions)20252024
Income from continuing operations, net of tax, attributable to The AES Corporation$46$432
Income tax benefit from continuing operations attributable to The AES Corporation(4)(19)
Pre-tax contribution42413
Unrealized derivatives, equity securities, and financial assets and liabilities gains(5)(85)
Unrealized foreign currency gains(7)(9)
Disposition/acquisition losses (gains)42(43)
Impairment losses3326
Loss on extinguishment of debt and troubled debt restructuring1034
Restructuring costs46—
Adjusted PTC$161$336

8377

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Adjusted EPS

We define Adjusted EPS as diluted earnings per share from continuing operations 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 the tax impact from the repatriation of sales proceeds, 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; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts.

The GAAP measure most comparable to Adjusted EPS is Diluted earnings per share from continuing operations. We believe that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company’s internal evaluation of financial performance. 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, or implement restructuring initiatives, which affect results in a given period or periods.

Adjusted EPS should not be construed as an alternative to Diluted earnings per share from continuing operations, which is determined in accordance with GAAP.

The Company reported diluted earnings per share of $0.60 for the three months ended March 31, 2024. For purposes of measuring earnings per share under U.S. GAAP, income available to AES common stockholders is reduced by increases in the carrying amount of redeemable stock of subsidiaries to redemption value. While the adjustment reduced earnings per share, it did not impact Net income on the Condensed Consolidated Statement of Operations. For purposes of computing Adjusted EPS, the Company excluded the adjustment to redemption value from the numerator. The table below reconciles the income available to AES common stockholders used in GAAP diluted earnings per share to the income from continuing operations used in calculating the non-GAAP measure of Adjusted EPS.

Reconciliation of Numerator Used for Adjusted EPSThree Months Ended March 31, 2024
(in millions, except per share data)IncomeShares$ per Share
GAAP DILUTED EARNINGS PER SHARE
Income available to The AES Corporation common stockholders$426712$0.60
Add back: Adjustment to redemption value of redeemable stock of subsidiaries6—0.01
NON-GAAP DILUTED EARNINGS PER SHARE$432712$0.61
Three Months Ended March 31,
Reconciliation of Adjusted EPS20252024
Diluted earnings per share from continuing operations$0.07$0.61
Unrealized derivatives, equity securities, and financial assets and liabilities gains(0.01)(0.12)(1)
Unrealized foreign currency gains(0.01)(0.01)
Disposition/acquisition losses (gains)0.06(2)(0.06)(3)
Impairment losses0.05(4)0.04(5)
Loss on extinguishment of debt and troubled debt restructuring0.010.04(6)
Restructuring costs0.06(7)—
Less: Net income tax expense (benefit)0.04(8)—
Adjusted EPS$0.27$0.50

(1)Amount primarily relates to net unrealized derivative gains at the Energy Infrastructure SBU of $68 million, or $0.10 per share.

(2)Amount primarily relates to losses on contingent consideration at AES Clean Energy of $28 million, or $0.04 per share, and day-one losses on commencement of sales-type leases at AES Renewable Holdings of $9 million, or $0.01 per share.

(3)Amount primarily relates to gain on dilution of ownership in Uplight due to its acquisition of AutoGrid of $52 million, or $0.07 per share, partially offset by the loss on partial sale of our ownership interest in Amman East and IPP4 in Jordan of $10 million, or $0.01 per share.

(4)Amount primarily relates to impairments at AES Clean Energy Development projects of $25 million, or $0.03 per share, and Mong Duong of $9 million, or $0.01 per share.

(5)Amount primarily relates to impairment at Mong Duong of $19 million, or $0.03 per share.

(6)Amount primarily relates to costs incurred due to troubled debt restructuring at Puerto Rico of $19 million, or $0.03 per share.

(7)Amount primarily relates to severance costs associated with the Company-wide restructuring program.

(8)Amount primarily relates to income tax expense associated with severance costs related to the Company-wide restructuring program of $10 million, or $0.01 per share, losses on contingent consideration at AES Clean Energy of $8 million, or $0.01 per share, and impairment at AES Clean Energy Development projects of $7 million, or $0.01 per share.

46 | The AES Corporation | March 31, 2025 Form 10-Q

Renewables SBU

The following table summarizes Operating Margin, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes (in millions) for the periods indicated:

Three Months Ended March 31,
20252024$ Change% Change
Operating Margin$73$63$1016%
Adjusted EBITDA (1)1611115045%
Adjusted EBITDA with Tax Attributes (1)289337(48)-14%

(1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition.

Operating Margin for the three months ended March 31, 2025 increased $10 million. This increase was primarily driven by a $36 million increase related to higher generation in Panama as a result of better hydrological conditions, $35 million positive impact from new businesses, and $22 million of prior year operating margin related to the AES Andes portfolio, which is reported in the Renewables SBU beginning in 2025 following the sale and expiration of certain coal-related assets and contracts. These positive impacts were partially offset by a $36 million increase in fixed costs primarily related to an accelerated growth plan, a $32 million impact from the sale of AES Brasil, and $16 million of one-time costs due to restructuring.

Adjusted EBITDA for the three months ended March 31, 2025 increased $50 million, primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, restructuring costs, and depreciation.

Adjusted EBITDA with Tax Attributes for the three months ended March 31, 2025 decreased $48 million, primarily driven by lower tax attributes realized in the current year due to timing of tax attribute recognition, partially offset by the increase in Adjusted EBITDA explained above. During the three months ended March 31, 2025 and 2024, we realized $128 million and $226 million, respectively, from tax attributes earned by our U.S. renewables business.

Utilities SBU

The following table summarizes Operating Margin, Adjusted EBITDA, Adjusted EBITDA with Tax Attributes, and Adjusted PTC (in millions) for the periods indicated:

Three Months Ended March 31,
20252024$ Change% Change
Operating Margin$155$120$3529%
Adjusted EBITDA (1)2231824123%
Adjusted EBITDA with Tax Attributes (1)2811849753%
Adjusted PTC (1) (2)1214180NM

(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 March 31, 2025 increased $35 million, driven primarily by $43 million due to higher retail rates as a result of the 2024 Base Rate Order, including the impact of certain riders now included in base rate; $20 million resulting from higher demand due to the impact of weather; and a $13 million increase in transmission and rider revenues. These increases are partially offset by a $13 million increase in depreciation expense from additional assets placed in service, higher amortization of regulatory assets, and changes in depreciation rates as a result of the 2024 Base Rate Order; an $8 million decrease due to the impact of planned outages; an $8 million decrease due to higher credit losses; and a $7 million decrease due to higher property taxes driven by higher assessed values.

Adjusted EBITDA for the three months ended March 31, 2025 increased $41 million, primarily due to the drivers above, adjusted for NCI, depreciation, and restructuring costs.

Adjusted EBITDA with Tax Attributes increased $97 million, mainly driven by the drivers above, as well as a $56 million increase in realized tax attributes, primarily related to the Pike County BESS project in the current year.

Adjusted PTC for the three months ended March 31, 2025 increased $80 million due to the drivers above, offset by higher depreciation expense.

47 | The AES Corporation | March 31, 2025 Form 10-Q

Energy Infrastructure SBU

The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated:

Three Months Ended March 31,
20252024$ Change% Change
Operating Margin$189$394$(205)-52%
Adjusted EBITDA (1)254356(102)-29%

(1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition.

Operating Margin for the three months ended March 31, 2025 decreased $205 million, driven by $96 million higher prior year revenues from the monetization of the Warrior Run coal plant PPA, $71 million due to prior year unrealized derivative gains as part of our commercial hedging strategy, $22 million of prior year operating margin at AES Andes, which is reported in the Renewables SBU beginning in 2025, and $17 million of one-time costs due to restructuring.

Adjusted EBITDA for the three months ended March 31, 2025 decreased $102 million, primarily due to the drivers above adjusted for NCI, unrealized derivatives, and restructuring costs.

New Energy Technologies SBU

The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated:

Three Months Ended March 31,
20252024$ Change% Change
Operating Margin$—$(2)$2100%
Adjusted EBITDA (1)(25)(17)(8)-47%

(1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition.

Operating Margin for the three months ended March 31, 2025 increased $2 million, with no material drivers.

Adjusted EBITDA for the three months ended March 31, 2025 decreased $8 million, primarily due to higher net losses at Fluence. The increased losses were mainly driven by a decline in sales, reflecting lower volumes fulfilled due to the timing of customer schedules.

Key Trends and Uncertainties

During 2025 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 2024 Form 10-K.

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 and CVD duties on certain imported cells and panels from Southeast Asia. Commerce’s determination and related matters remain the subject of ongoing litigation.

In 2024, Commerce and the U.S. International Trade Commission (“USITC”) initiated new AD/CVD investigations on solar cells and panels imported from Southeast Asia. On April 18, 2025, Commerce rendered final affirmative AD/CVD determinations with respect to all four countries. The ITC’s final determination is expected to be announced May 20, 2025. A final affirmative determination by the ITC would result in the issuance of new AD/CVD orders in early June 2025. We do not expect a final affirmative AD/CVD determination by ITC to have a negative impact on our business.

48 | The AES Corporation | March 31, 2025 Form 10-Q

Separately, the U.S. maintains a global safeguard tariff (currently 14% ad valorem) on solar cells and modules pursuant to the Section 201 Safeguard Action on crystalline silicon photovoltaic products, which became effective in February 2018. On June 21, 2024, President Biden issued Proclamation 10779, revoking the exclusion of bifacial panels from safeguard relief previously proclaimed in Proclamation 10339, and reinstating the tariff on bifacial panels under the Section 201 Safeguard Action, subject to certain qualifications. These global tariffs are expected to expire in February 2026.

The U.S. also maintains Section 301 tariffs on certain Chinese made lithium-ion batteries and related components utilized for energy storage systems, with such tariff currently set at 7.5% and increasing to 25% effective January 1, 2026. There is also an ongoing AD/CVD investigation with respect to exports by China of natural and synthetic graphite used to make lithium-ion battery anode material. Any determinations or orders arising from such investigation could result in price increases.

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 Section 232 tariffs on steel and aluminum imports to expand their scope of applicability and imposing 25% tariffs on both products. At this time, we do not expect the modifications to tariffs on steel and aluminum to 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”) and imposing a 10% additional tariff on imports from China, effective February 4, 2025. Effective March 4, 2025, this tariff was increased to 20%.

On April 2, 2025, President Trump issued an Executive Order pursuant to IEEPA imposing an indefinite, baseline reciprocal 10% tariff on almost all goods imported into the U.S., effective April 5, 2025, and individualized higher IEEPA tariffs (11% to 50%) starting April 9, 2025 on goods originating from 57 countries with trade surpluses with the U.S. On April 9, 2025, the U.S. government issued a further Executive Order increasing the IEEPA reciprocal tariff on China to 125% effective April 10, 2025. Concurrently, the U.S. government announced a temporary suspension of the country-specific reciprocal tariff measures targeting most U.S. trading partners for a 90-day period, or until July 9, 2025.

During the 90-day suspension, many countries have been seeking to reach bilateral trade agreements with the U.S. and the ultimate outcome of any reciprocal or other tariffs with these countries is uncertain.

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. and we expect limited impact to projects scheduled to become operational in 2025 through 2027 due to the recently announced tariffs on China.

The impact of new tariffs, reciprocal tariffs, or Commerce investigations, the impact of any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, 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.

More specifically, we have contracted and imported into the U.S. all of the solar panels that are necessary to complete our U.S. backlog of solar projects scheduled to finish construction and become operational in 2025. For our U.S backlog of solar projects scheduled to finish construction and become operational in 2026 or 2027, we have contracted for all of our panel supply needs, with the majority of such panels being manufactured in the U.S. and most of the remaining panels have already been imported into the U.S.

Additionally, we have contracted and imported into the U.S. all the batteries needed for our U.S. energy storage projects scheduled to be completed in 2025.

49 | The AES Corporation | March 31, 2025 Form 10-Q

For our backlog of storage projects scheduled to finish construction and become operational in 2026 or 2027, we have contracted for approximately 80% of our battery needs, with almost all of such batteries coming from U.S. or Korean suppliers. We are also well advanced in contracting 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 2025 through 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.

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

According to the National Oceanic and Atmospheric Administration ("NOAA"), weather conditions are currently transitioning from weak La Niña conditions to ENSO-neutral. The ENSO forecast indicates a high probability (91%) for ENSO-neutral conditions forming March-May 2025, and these conditions are favored to continue through September-November 2025.

Inflows during the first quarter of the year have been relatively stable across the region, reflecting the influence of, and transition to, ENSO-neutral condition. In Panama, overall system inflows have been only slightly below historical average conditions, except for the Bayano reservoir, which registered above-average hydrology conditions. Higher hydrology may result in energy surpluses after covering the contracted hydro positions, available to be sold in the spot market.

In Colombia, hydrological conditions were generally aligned with seasonal expectations and historical average conditions, supporting steady flows into key reservoirs and reducing the risk of extreme droughts or floods typically associated with El Niño or La Niña.

In Chile, the primary driver for AES’ hydro assets is snowpack volumes and winter rains, mainly in the central regions. Over the first quarter of 2025, precipitation and snowpack accumulation was within the range of historical averages.

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 to our businesses beyond hydrology, including with respect to power generation from other renewable sources of energy and demand. Even if rainfall and water inflows 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

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

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

Our U.S. renewables business has a backlog of approximately 7.6 GW and a 53 GW pipeline that we intend to utilize to continue to grow our business, and these changes in tax policy are supportive of this strategy. We account for U.S. renewables projects according to U.S. GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the investment tax credit begins in the quarter the

50 | The AES Corporation | March 31, 2025 Form 10-Q

project is placed in service. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy.

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

In 2024, we realized $1,313 million of earnings from Tax Attributes, comprised of $1,293 million from the Renewables SBU and $20 million from the Utilities SBU. In 2025, we expect an increase in Tax Attributes earned throughout the year by our U.S. renewables business in line with the growth in that business. For the three months ended March 31, 2025, we recognized $186 million in tax attributes.

The implementation of the IRA requires substantial guidance from the U.S. Department of Treasury and other government agencies. Some of the guidance and rulemaking enacted under the Biden Administration could be changed or modified by the Trump Administration, creating uncertainty with respect to implementation of the IRA. Also, the Trump Administration has issued Executive Orders that pause certain funding allocated to projects under the Infrastructure Investment and Jobs Act (IIJA) and the IRA during a 90-day review process. As they currently stand, these Executive Orders do not impact the tax credits under the IRA.

It remains uncertain whether Congress will modify or repeal the IRA in connection with the budget reconciliation process or otherwise. While we have taken significant measures to protect against the impact of changes to the IRA, including by implementing a program to ensure our backlog of U.S. renewables projects satisfy IRS safe harbor requirements for qualifying for the ITCs and PTCs, the impacts from any modifications or repeal of the IRA may be material to our results of operations.

Global Tax — The macroeconomic and political environments in the U.S. and in some countries where our subsidiaries conduct business have changed in recent years. This could result in significant impacts to future tax law. In the U.S., the IRA includes a 15% corporate alternative minimum tax (“CAMT”) based on adjusted financial statement income. In September 2024, the IRS released proposed regulations on the 15% CAMT. The impact to the Company in 2025 is not expected to be material.

The Netherlands, Bulgaria, and Vietnam adopted legislation to implement Pillar 2 effective as of January 1, 2024. We will continue to monitor the issuance of draft legislation in other non-EU countries where the Company operates that are considering Pillar 2 amendments and new interpretive guidance.

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

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

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

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

51 | The AES Corporation | March 31, 2025 Form 10-Q

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. Of this amount, $15 billion will be available in 2025. 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.

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 2024 Form 10-K, our subsidiaries in Puerto Rico have long-term PPAs with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

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

PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Ilumina’s non-recourse debt of $22 million continues to be in technical default and is classified as current as of March 31, 2025.

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. On April 25, 2025, the Oversight Board filed a status report seeking to extend the mediation period for six months through October 31, 2025.

Considering the information available as of the date hereof, management believes the carrying amount of our long-lived assets in Puerto Rico of $751 million is recoverable as of March 31, 2025.

Decarbonization Initiatives

Our strategy involves shifting towards clean energy platforms, including renewable energy, energy storage, LNG, and modernized grids. It is designed to position us for continued growth while reducing our carbon intensity and to be in support of our mission of accelerating the future of energy, together. We have made significant progress on our exit of coal generation, and by year-end 2025, we intend to have exited the substantial majority of our coal facilities that we owned in 2022. Due to a number of factors, including grid and market dynamics, we will continue to work towards exiting coal in the limited markets where we have coal generation. We currently anticipate these efforts will continue beyond 2027. We expect to further reduce the carbon intensity of our operations as we add more long-term contracted renewables to the grid each year.

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

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

52 | The AES Corporation | March 31, 2025 Form 10-Q

For further information about the risks associated with decarbonization initiatives, see Item 1A.—Risk Factors—Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses included in the 2024 Form 10-K.

Regulatory

FERC, RTOs, and Interconnection Prioritization — On February 11, 2025, FERC approved PJM's request for a one-time change in its interconnection process to expedite the interconnection of a limited number of high-capacity resources to support near-term resource adequacy and grid reliability. This change to PJM's interconnection process is not expected to impact the PJM projects already in our backlog since they have received interconnection approvals. However, it will likely create uncertainty and delays in the time for interconnection approvals for our development pipeline of renewables projects in PJM. Other RTOs are considering similar proposals to expedite interconnection approvals for certain high-capacity resources. See Item 1A.—Risk Factors - Our development projects are subject to substantial uncertainties included in the 2024 Form 10-K for further details.

U.S. Executive Orders — A recent Executive Order has required a review of all federal onshore wind leasing and federal permitting practices. In executing this order, the Department of Interior and other agencies have paused federal permitting for all wind projects on federal lands and private lands with a federal nexus. Our U.S. renewables projects are developed primarily on private land and are designed in a manner that minimizes the potential of a federal nexus. At this time, we do not expect this Order to have a significant impact on our business.

AES Maritza PPA Review — DG Comp is conducting a preliminary review of whether AES Maritza’s PPA with NEK is compliant with the European Union's State Aid rules. No formal investigation has been launched by DG Comp to date. AES Maritza has previously engaged in discussions with the DG Comp case team and the Government of Bulgaria (“GoB”) to attempt to reach a negotiated resolution of the DG Comp’s review (“PPA Discussions”). There are no active PPA Discussions at present but those discussions could resume at any time. The PPA continues to remain in place. However, there can be no assurance that, in the context of DG Comp’s preliminary review or any future PPA Discussions, the other parties will not seek a prompt termination of the PPA.

We do not believe termination of the PPA is justified. Nevertheless, the PPA Discussions involved a range of potential outcomes, including but not limited to the termination of the PPA and payment of some level of compensation to AES Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict whether and when the PPA Discussions might resume or the outcome of any such discussions. Nor can we predict how DG Comp might resolve its review if the PPA Discussions do not resume or if any such discussions fail to result in an agreement concerning the agency's review. AES Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurance that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of operations, and cash flows. As of March 31, 2025, the carrying value of our long-lived assets at Maritza is $318 million.

AES Ohio Smart Grid Phase 2 Filing — In February 2024, AES Ohio filed a Smart Grid Phase 2 with the PUCO proposing a ten-year investment plan to begin after Smart Grid Phase 1 ends. On September 13, 2024, AES Ohio reached a settlement with the PUCO Staff and other parties on the pending Smart Grid Phase 2 Application. The Settlement will provide for a four-year plan to invest $241 million of capital and $19 million of operations and maintenance expense related to grid modernization, support of Distributed Energy Resources and Economic Development, and an enhanced Telecommunications network. These costs will be recovered through the existing Investment Infrastructure Rider. An evidentiary hearing was held on October 29, 2024, and we expect an order from PUCO by the second quarter of 2025, prior to the end of Smart Grid Phase 1.

AES Ohio Distribution Rate Case — On November 29, 2024, AES Ohio filed a new distribution rate case with the PUCO. The investments reflected in the distribution rate case include investments to enhance the safety, reliability, and resilience of the distribution system. Among other matters, the application requests: (i) an increase to its annual distribution revenue requirement of $235 million, which incorporates certain investments that are currently recovered through the Distribution Investment Rider; (ii) a return on equity of 10.95% and a cost of long-term debt of 4.49% on a distribution rate base of $1.3 billion and based on a capital structure of 53.87% equity and 46.13% long-term debt; and (iii) a date certain of September 30, 2024 and a test period of June 1, 2024 – May 31, 2025. The rate case application also includes a proposal for increased tree-trimming expenses. AES Ohio proposed an evidentiary

53 | The AES Corporation | March 31, 2025 Form 10-Q

hearing to be held beginning June 2, 2025; however, the PUCO has not yet established a procedural schedule for the proceeding.

AES Ohio Legislation — On April 30, 2025, the Ohio legislature passed new energy legislation (HB 15) that will be sent to the Governor for signature or veto. As passed by the state legislature, the legislation would allow Ohio's electric utilities to file three-year forecasted base distribution rate cases, which would replace electric security plans and associated recovery riders. Among other provisions, the legislation would also eliminate the Legacy Generation Resource Rider, which allows for recovery of net OVEC costs and revenues. As of March 31, 2025, AES Ohio's Legacy Generation Resource Rider regulatory asset balance was $9.7 million which we would continue to collect, in an amount based, among other things, on customer usage and rates through the effective date of the legislation, if signed by the Governor. Changes to the regulatory framework from this legislation, including not recovering any remaining regulatory asset balance amount or future net OVEC costs and revenue, could be material to our results of operations, financial condition, and cash flows.

Foreign Exchange Rates

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

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

Impairments and Realizability

Long-lived Assets and Current Assets Held-for-Sale — During the three months ended March 31, 2025, the Company recognized asset impairment expense of $49 million. See Note 16*—Asset Impairment Expense* included in Item 1.—Financial Statements of this Form 10-Q for further information. After recognizing this impairment expense, the carrying value of long-lived assets and current assets held-for-sale that were assessed for impairment totaled $490 million at March 31, 2025.

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 $237 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.

Environmental

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

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potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses included in the 2024 Form 10-K.

CSAPR — CSAPR addresses the “good neighbor” provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. The CSAPR required significant reductions in SO2 and NOx emissions from power plants in many states in which subsidiaries of the Company operate. The Company is required to comply with the CSAPR in certain states, including Indiana and Maryland. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. The Company complies with CSAPR through operation of existing controls and purchases of allowances on the open market, as needed.

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

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

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

Mercury and Air Toxics Standard — In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective and AES facilities implemented measures to comply, as applicable. In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA and subsequently remanded MATS to the EPA without vacatur. On May 22, 2020, the EPA published a final finding that it is not “appropriate and necessary” to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units (“EGUs”) (reversing its prior 2016 finding), but that the EPA would not remove the source category from the CAA Section 112(c) list of source categories and would not change the MATS requirements. On March 6, 2023, the EPA published a final rule to revoke its May 2020 finding and reaffirm its 2016 finding that it is appropriate and necessary to regulate these emissions. On April 24, 2023, the EPA published a proposed rule, the MATS Risk and Technology Review (“RTR”) Rule to lower certain emissions limits and revise certain other aspects of MATS. On May 7, 2024, the EPA published a final rule to revise MATS for coal and oil-fired EGUs. The final rule became effective on July 8, 2024. The final rule lowers certain emissions limits and revises certain other aspects of MATS. The MATS RTR Rule is subject to legal challenges. On October 4, 2024, the U.S. Supreme Court denied emergency stay applications.

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

Climate Change Regulation — The final NSPS for CO2 emissions from new, modified, and reconstructed

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fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015. Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit Court. On December 20, 2018, the EPA published proposed revisions to the final NSPS for new, modified, and reconstructed coal-fired electric utility steam generating units. The EPA proposed that the Best System of Emissions Reduction (“BSER”) for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration (“CCS”), which had been the BSER for these units in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal. Challenges to the GHG NSPS remain held in abeyance at this time. On May 23, 2023, the EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023. On May 9, 2024, the EPA published the final NSPS requiring carbon capture and sequestration for new and reconstructed baseload stationary combustion turbines, among other requirements. The EPA did not finalize revisions to the NSPS for newly constructed or reconstructed coal-fired electric utility steam generating units as proposed in 2018.

On July 8, 2019, the EPA published the final Affordable Clean Energy (“ACE”) Rule which would have established CO2 emission rules for existing power plants under CAA Section 111(d) and would have replaced the EPA's 2015 Clean Power Plan Rule (“CPP”). However, on January 19, 2021, the D.C. Circuit vacated and remanded the ACE Rule. Subsequently, on June 30, 2022, the Supreme Court reversed the judgment of the D.C. Circuit Court and remanded for further proceedings consistent with its opinion holding that the “generation shifting” approach in the CPP exceeded the authority granted to the EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate, holding pending challenges to the ACE Rule in abeyance while the EPA developed a replacement rule. On May 23, 2023, the EPA published a proposed rule that would vacate the ACE Rule and proposed New Source Performance Standards (“NSPSs”) that would establish emissions guidelines in the form of CO2 emissions limitations for certain existing electric generating units (“EGUs”) and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as the EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operation to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s. On May 9, 2024, the EPA published the final rule regulating GHGs from existing EGUs pursuant to Section 111(d) of the Clean Air Act and effective on July 8, 2024. Existing EGUs are those that were constructed prior to January 8, 2014. Depending on various EGU-specific factors, the bases of emissions guidelines for natural gas-fired units include the use of uniform fuels and routine methods of operation and maintenance and the bases of emissions guidelines for coal-fired units include 40% natural gas co-firing or carbon capture and sequestration with 90% capture of 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 October 16, 2024, the U.S. Supreme Court denied emergency stay applications. The impact of the rules, the results of further proceedings, and potential future greenhouse gas emissions regulations remain uncertain but could be material.

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

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D.C. Circuit dismissed the challenges. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

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

On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. If this rule is finalized before Indiana establishes a final state-level CCR permit program, AES Indiana could eventually be required to apply for a federal CCR permit from the EPA. On December 21, 2022, the Indiana Department of Environmental Management (“IDEM”) published in the Indiana Register a Second Notice of Comment Period for its proposed CCR rulemaking which would include regulation of CCR through a state permitting program. On August 7, 2024, in response to changes to Indiana statute, as well as comments received during the Second Notice of Comment Period, IDEM published a Continuation of the Second Notice of Comment Period for proposed amendments to the draft rule language for a State CCR Permitting Program.

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

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

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

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

Water Discharges — In June 2015, the EPA and the U.S. Army Corps of Engineers ("the Agencies") published a rule defining federal jurisdiction over waters of the U.S., known as the "Waters of the U.S." (“WOTUS”) rule. WOTUS defines the geographic reach and authority of the Agencies to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the proper standard for how to properly determine whether a wetland or stream that is not navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (“Decision”) in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a clear standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional.

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

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash, and more stringent effluent limitations for flue gas desulfurization wastewater. AES Indiana Petersburg has installed a dry bottom ash handling system in response to the CCR rule and wastewater treatment systems in response to the NPDES permits in advance of the ELG compliance date. Other U.S. businesses already include dry handling of fly ash and bottom ash and do not generate flue gas desulfurization wastewater. Following the 2019 U.S. Court of Appeals vacatur and remand of portions of the 2015 ELG rule related to leachate and legacy water, on March 29, 2023, the EPA published a proposed rule revising the 2020 Reconsideration Rule. On May 9, 2024, the EPA published a final rule which became effective on July 8, 2024. The final rule established more stringent best available technology limits for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate and established a new set of definitions and new limits for combustion residual leachate and legacy wastewater. The May 2024 rule is subject to legal challenges. On October 10, 2024, the Eighth Circuit Court denied stay applications. 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.

U.S. Executive Actions Affecting Environmental Regulations — On January 20, 2025, President Trump issued an Executive Order directing Agencies to, among other tasks, review regulations issued under the prior administration to determine whether they should be suspended, revised, or rescinded. President Trump also issued a Memorandum directing agencies to refrain from proposing or issuing any rules until the current administration has reviewed and approved those rules. In accordance with these and other 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 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 March 31, 2025, the Company had unrestricted cash and cash equivalents of $1.8 billion, of which $151 million was held at the Parent Company and qualified holding companies. The Company had $64 million in short-term investments, held primarily at subsidiaries, and restricted cash and debt service reserves of $813 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $24 billion and $6 billion, respectively. Of the $3 billion of our current non-recourse debt, $2.8 billion was presented as such because it is due in the next twelve months and $178 million relates to debt considered in default. AES Puerto Rico is in payment default. All other 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. Additionally, on February 6, 2025, AES Dominican Renewable Energy failed to comply with a covenant on its debt of $353 million, resulting in a technical default. AES Dominican Renewable Energy is classified as held-for-sale as of March 31, 2025, therefore the associated non-recourse debt is classified in Current held-for-sale liabilities on the Condensed Consolidated Balance Sheet. See Note 8—Obligations and Note 18—Held-For-Sale and Dispositions in Item 1.—Financial Statements of this Form 10-Q for additional detail. As of March 31, 2025, the Company also had $605 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 $1.2 billion in recourse debt which matures within the next twelve months, including $255 million in outstanding borrowings under the commercial paper program. Furthermore, we have $416 million due under supplier financing arrangements that have a guarantee, $301 million guaranteed by the Parent Company and $115 million guaranteed by subsidiaries.

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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 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. 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 $30.3 billion of total gross debt outstanding as of March 31, 2025, approximately $9.4 billion accrues interest at variable rates. 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 March 31, 2025, the total maximum outstanding amount of hedges protecting the company against variable rate exposure was $8.3 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 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 March 31, 2025, 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 $4.3 billion in aggregate (excluding those 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 March 31, 2025, we had $324 million in letters of credit under bilateral agreements, $107 million in letters of credit outstanding provided under our unsecured credit facilities, and $19 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. During the quarter ended March 31, 2025, the Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.

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 March 31, 2025, the maximum undiscounted potential exposure to guarantees and letters of credit issued by our subsidiaries was $5.4 billion, including $1.9 billion of customary payment guarantees under EPC contracts and other agreements, $1.4 billion of letters of credit

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outstanding, $1.2 billion of surety bonds and other guarantees issued by insurance companies, and $828 million of tax equity financing related guarantees.

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 March 31, 2025, the Company had approximately $106 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 March 31, 2026, or one year from the latest balance sheet date. Noncurrent receivables in the U.S. pertain primarily 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 March 31, 2025, the Company had $934 million of loans receivable related to the Mong Duong facility in Vietnam, which was constructed under a build, operate, and transfer 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. As of March 31, 2025, Mong Duong met the held-for-sale criteria and the loan receivable balance, net of CECL reserves of $23 million, was classified in Current held-for-sale assets. See 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 three months ended March 31, 2025 were debt financings, cash flows from operating activities, purchases under supplier financing arrangements, and sales to noncontrolling interests. The primary uses of cash in the three months ended March 31, 2025 were repayments of debt, capital expenditures, and repayments of obligations under supplier financing arrangements.

The primary sources of cash for the Company in the three months ended March 31, 2024 were debt financings, purchases under supplier financing arrangements, and cash flows from operating activities. The primary uses of cash in the three months ended March 31, 2024 were capital expenditures, repayments of debt, and repayments of obligations under supplier financing arrangements.

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A summary of cash-based activities is as follows (in millions):

Three Months Ended March 31,
Cash Sources:20252024
Issuance of non-recourse debt$1,293$2,131
Borrowings under the revolving credit facilities1,1871,741
Issuance of recourse debt800—
Net cash provided by operating activities545287
Purchases under supplier financing arrangements317486
Commercial paper borrowings (repayments), net255719
Sales to noncontrolling interests245125
Sale of short-term investments33141
Other78133
Total Cash Sources$4,753$5,763
Cash Uses:
Capital expenditures (1)$(1,254)$(2,148)
Repayments of recourse debt(774)—
Repayments of non-recourse debt(759)(915)
Repayments of obligations under supplier financing arrangements(628)(516)
Repayments under revolving credit facilities(451)(1,037)
Dividends paid on AES common stock(125)(116)
Purchase of short-term investments(18)(144)
Other(217)(322)
Total Cash Uses$(4,226)$(5,198)
Net increase in Cash, Cash Equivalents, and Restricted Cash$527$565

(1)Includes interest capitalized on development and construction of $124 million and $157 million for the three months ended March 31, 2025 and 2024, respectively. Of the total capitalized, $118 million and $154 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 three-month period (in millions):

Three Months Ended March 31,
Cash flows provided by (used in):20252024$ Change
Operating activities$545$287$258
Investing activities(1,282)(2,386)1,104
Financing activities1,3172,606(1,289)

Operating Activities

Net cash provided by operating activities increased $258 million for the three months ended March 31, 2025, compared to the three months ended March 31, 2024.

Operating Cash Flows

(in millions)

141

(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.

61 | The AES Corporation | March 31, 2025 Form 10-Q

  • Adjusted net income decreased $353 million, primarily due to lower margin at our Energy Infrastructure SBU and a decrease in interest income; partially offset by higher margin at our Utilities and Renewables SBUs and a decrease in cash paid for interest.

  • Change in working capital increased $611 million, primarily due to a decrease in prepaid expense and other assets due to the timing of collection of tax credit transfer proceeds and the prior period change in receivables at Warrior Run; a decrease in receivables and increase in payables due to timing of collections and billings.

Investing Activities

Net cash used in investing activities decreased $1.1 billion for the three months ended March 31, 2025, compared to the three months ended March 31, 2024.

Investing Cash Flows

(in millions)

143

  • Acquisitions of business interests decreased $53 million, primarily due to the prior year acquisition of Hoosier Wind.

  • Capital expenditures decreased $894 million, discussed further below.

Capital Expenditures

(in millions)

761

(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 decreased $843 million, primarily driven by a decrease in expenditures for U.S. renewables projects compared to the prior year.

  • Maintenance expenditures decreased $51 million, primarily driven by a $27 million decrease at AES Indiana due to the timing of maintenance, and a $19 million decrease due to the sale of AES Brasil in October 2024.

62 | The AES Corporation | March 31, 2025 Form 10-Q

Financing Activities

Net cash provided by financing activities decreased $1.3 billion for the three months ended March 31, 2025, compared to the three months ended March 31, 2024.

Financing Cash Flows

(in millions)

147

See Notes 1—Financial Statement Presentation, 8—Obligations, and 12—Equity in Item 1.—Financial Statements of this Form 10-Q for more information regarding significant transactions.

*•*The 682 million impact from non-recourse debt transactions is mainly due to $1.4 billion of higher net borrowings at the Energy Infrastructure and Utilities SBUs in the prior year, which included $273 million related to the sale of future revenue at Warrior Run which was recorded as non-recourse debt; partially offset by $705 million of higher net borrowings at the Renewables SBU in the current year.

  • The $464 million impact from commercial paper and $110 million impact from the Parent Company revolver are due to higher net borrowings in the prior year.

  • The $281 million impact from supplier financing arrangements is primarily due to higher net cash outflows at the Renewables SBU.

  • The $142 million impact from non-recourse revolvers is primarily due to $129 million of higher net repayments at the Energy Infrastructure SBU in the prior year and $80 million of higher net borrowings at the Renewables SBU in the current year, partially offset by $68 million of higher net borrowings at the Utilities SBU in the prior year.

  • The $120 million impact from sales to noncontrolling interests is primarily due to $150 million at AES Indiana from the sale of ownership in the Pike County BESS project to a tax equity investor, partially offset by a $26 million decrease in sales under the Chile Renovables partnership with GIP.

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 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

63 | The AES Corporation | March 31, 2025 Form 10-Q

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):

March 31, 2025December 31, 2024
Consolidated cash and cash equivalents$1,753$1,524
Less: Cash and cash equivalents at subsidiaries(1,602)(1,259)
Parent Company and qualified holding companies’ cash and cash equivalents151265
Commitments under the Parent Company credit facilities1,8001,800
Less: Letters of credit under the credit facilities(19)(18)
Less: Borrowings under the commercial paper program(255)—
Borrowings available under the Parent Company credit facilities1,5261,782
Total Parent Company Liquidity$1,677$2,047

The Parent Company paid dividends of $0.17595 per outstanding share to its common stockholders during the first quarter of 2025 for dividends declared in December 2024. 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 billion and $5.7 billion as of March 31, 2025 and December 31, 2024, 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 2024 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 2024 Form 10-K for additional information.

Various debt instruments at the Parent Company level, including our revolving credit facilities 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 March 31, 2025, 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 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.

64 | The AES Corporation | March 31, 2025 Form 10-Q

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 billion. The portion of current debt related to such defaults was $178 million at March 31, 2025, all of which was non-recourse debt related to three subsidiaries: AES Puerto Rico, AES Ilumina, and AES Jordan Solar. AES Puerto Rico is in payment default. All other 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. Additionally, on February 6, 2025, AES Dominican Renewable Energy failed to comply with a covenant on its debt of $353 million, resulting in a technical default. AES Dominican Renewable Energy is classified as held-for-sale as of March 31, 2025, therefore the associated non-recourse debt is classified in Current held-for-sale liabilities on the Condensed Consolidated Balance Sheet. See Note 8—Obligations and Note 18—Held-For-Sale and Dispositions 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 March 31, 2025, 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 March 31, 2025, 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 2024 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 2024 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 three months ended March 31, 2025.

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