ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For discussion of the Company's year ended December 31, 2024 compared to the year ended December 31, 2023, refer to Item 7. —Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Form 10-K filed with the SEC on March 11, 2025.
Executive Summary
In 2025, AES delivered on its strategic and financial objectives. We completed construction of 3.2 GW of renewables and energy storage, and signed long-term PPAs for an additional 4.0 GW of new renewable energy. See Overview of our Strategy included in Item 1.— Business of this Form 10-K for further information.
Compared with last year, net income decreased $640 million, from $802 million to $162 million. This decrease is mainly driven by the prior year gain on sale of AES Brasil, lower earnings at the Energy Infrastructure SBU primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA and lower net derivative gains, higher day-one losses on the commencement of sales-type leases at AES Clean Energy, and higher unrealized foreign currency losses; partially offset by income tax benefit mainly driven by tax credit transfers compared to prior year income tax expense, higher contributions from new projects and better hydrology in the Renewables SBU, and higher retail margin at the Utilities SBU under the 2024 Base Rate Order at AES Indiana and the 2024 DRC Settlement at AES Ohio.
Adjusted EBITDA, a non-GAAP measure, increased $232 million, from $2,639 million to $2,871 million, mainly driven by higher contributions from new projects and better hydrology in the Renewables SBU, and higher retail margin at the Utilities SBU; partially offset by higher prior year revenues from the monetization of the Warrior Run coal plant PPA in the Energy Infrastructure SBU, the sale of AES Brasil in the prior year, and the impact of the AES Ohio and AGIC sell-downs.
Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $459 million, from $3,952 million to $4,411 million, primarily due to the drivers above as well as higher realized tax attributes driven by higher income from tax credit transfers.
Compared with last year, diluted earnings per share from continuing operations decreased $1.06, from $2.37 to $1.31. This decrease is mainly driven by the prior-year gain on sale of AES Brasil, lower earnings at the Energy Infrastructure SBU primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA and lower net derivative gains, higher day-one losses on commencement of sales-type leases at AES Clean Energy, higher unrealized foreign currency losses, and impairments related to Uplight. These were partially offset by higher income tax benefit mainly driven by tax credit transfers compared to prior year income tax expense, and contributions from new projects and better hydrology in the Renewables SBU.
Adjusted EPS, a non-GAAP measure, increased $0.20 from $2.14 to $2.34, mainly driven by a lower adjusted tax rate, including the impact of tax credit transfers, and higher realized tax attributes and retail margin at the Utilities SBU; partially offset by lower realized tax attributes at the Renewables SBU due to timing of tax attribute recognition and lower contributions from the Energy Infrastructure SBU primarily due to higher prior year revenues from the monetization of the Warrior Run coal plant PPA.
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Review of Consolidated Results of Operations
Years Ended December 31,
$ Change
% Change
(in millions, except per share amounts)
Revenue:
Renewables SBU
Utilities SBU
Energy Infrastructure SBU
New Energy Technologies SBU
Corporate and Other
Eliminations
Total Revenue
Operating Margin:
Renewables SBU
Utilities SBU
Energy Infrastructure SBU
New Energy Technologies SBU
Corporate and Other
Eliminations
Total Operating Margin
General and administrative expenses
Interest expense
Interest income
Loss on extinguishment of debt
Other expense
Other income
Gain on disposal and sale of business interests
Asset impairment expense
Foreign currency transaction gains (losses)
Other non-operating expense
Income tax benefit (expense)
Net equity in losses of affiliates
INCOME (LOSS) FROM CONTINUING OPERATIONS
Loss from disposal of discontinued businesses, net of income tax expense of $0 and $7, respectively
NET INCOME (LOSS)
Less: Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION
Net cash provided by operating activities
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 Consolidated Statements of Operations. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.
Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, O&M costs, depreciation and amortization expenses, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.
Operating margin is defined as revenue less cost of sales.
Consolidated Revenue and Operating Margin
Year Ended December 31, 2025
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Revenue
(in millions)
Consolidated Revenue — Revenue decreased $45 million in 2025 compared to 2024, driven by:
• $805 million at Energy Infrastructure primarily driven by $921 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; $174 million due to prior year unrealized and realized derivative gains, $171 million of prior year revenues from the monetization of the Warrior Run coal plant PPA, and $23 million due to the prior year sell-down of Amman East and IPP4 in Jordan; partially offset by $317 million due to higher fuel prices and transportation costs passed through to the offtaker, $148 million of higher CO 2 purchases passed through due to higher production, and $28 million due to higher availability; and
• $50 million at Corporate, Other and Eliminations mainly driven by higher eliminations of inter-segment revenue.
These unfavorable impacts were partially offset by increases of:
• $514 million at Utilities mainly driven by $422 million increase in transmission, distribution, rider, and wholesale revenues mainly due to higher rates, and $93 million due to higher net retail demand mainly driven by favorable weather; and
• $296 million at Renewables mainly driven by an $832 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, $232 million due to new projects in service, and $105 million due to development services in the U.S.; partially offset by a $615 million decrease due to the sale of AES Brasil, $243 million net lower spot sales and prices, mainly in Colombia, and a $42 million decrease related to changes in mark-to-market of energy derivatives.
Operating Margin
(in millions)
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Consolidated Operating Margin — Operating margin decreased $103 million, or 4%, in 2025 compared to 2024, driven by:
• $332 million at Energy Infrastructure mainly driven by $160 million higher prior year revenues from the monetization of the Warrior Run coal plant PPA, $108 million due to prior year net derivative gains as part of our commercial hedging strategy, $60 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, $23 million of lower LNG sales net of higher terminal fees, $18 million of one-time costs due to restructuring, and $17 million due to the prior year sell-down of Amman East and IPP4 in Jordan; partially offset by $49 million driven by higher availability in 2025 due to lower maintenance.
These unfavorable impacts were partially offset by increases of:
• $104 million at Renewables mainly driven by $91 million due to development services in the U.S., $89 million from new businesses, $68 million in Colombia as a result of increased availability and lower spot prices on energy purchases, $60 million due to the results of AES Andes moving to Renewables in 2025, as described above, and $36 million due to higher generation in Panama as a result of better hydrological conditions during the first quarter of 2025. These increases were partially offset by a $177 million decrease due to the sale of AES Brasil, a $42 million decrease related to changes in mark-to-market of energy derivatives, a $38 million increase in fixed costs primarily related to an accelerated growth plan, and $15 million of one-time costs due to restructuring;
• $92 million at Utilities mainly driven by $191 million due to higher retail rates as a result of the AES Indiana 2024 Base Rate Order and AES Ohio 2024 DRC Settlement, higher transmission and rider revenues, and higher demand due to the impact of weather; partially offset by a $46 million increase in depreciation expense from additional assets placed in service, a $33 million increase in fixed cost mainly driven by higher property taxes, and a $14 million impact of planned outages; and
• $37 million at Corporate and Other mainly driven by higher premiums earned by AGIC and lower eliminations of insurance recoveries booked at the businesses related to AGIC.
See Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-K for additional discussion and analysis of operating results for each SBU.
Consolidated Results of Operations — Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and initiatives, executive management, finance, legal, human resources, and information systems, as well as global development costs.
General and administrative expenses decreased $47 million, or 16%, to $241 million in 2025 compared to $288 million in 2024, primarily due to a $34 million decrease in business development costs, driven by the Company's restructuring program, $18 million lower IT costs, and $8 million lower professional fees, partially offset by $14 million of one-time costs due to restructuring.
Interest expense
Interest expense decreased $78 million, or 5%, to $1,407 million in 2025, compared to $1,485 million in 2024. This decrease is primarily due to a $200 million impact from the sale of AES Brasil in October 2024 and lower debt balances at the Energy Infrastructure SBU; partially offset by lower capitalized interest at the Renewables SBU due to fewer projects under construction, and a higher weighted average interest rate and debt balance at the Parent Company.
Interest income
Interest income decreased $94 million, or 25%, to $287 million in 2025, compared to $381 million in 2024, primarily due to a $46 million impact from the sale of AES Brasil in October 2024, prior year interest recognized of $34 million on the Stabilization Fund receivables in Chile, and a $24 million decrease at Argentina due to lower short-term investments at lower rates; partially offset by a $15 million increase in sales type lease receivables at the Renewables SBU.
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Loss on extinguishment of debt
Loss on extinguishment of debt increased $9 million, or 53%, to $26 million in 2025, compared to $17 million in 2024. This increase was primarily driven by a $9 million loss related to a revolver amendment and prepayment of debt at AES Clean Energy, a $7 million loss due to prepayment of debt at Jordan Solar, and a $5 million loss due to prepayment of senior notes at Mercury Chile; partially offset by a prior year loss of $10 million due to a prepayment at AES Andes.
See Note 12— O bligations included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Other income
Other income decreased $89 million, or 57%, to $67 million in 2025, compared to $156 million in 2024 primarily due to the prior year recognition of a $20 million bargain purchase gain on the Madison and Birdseye acquisition, a prior year gain of $14 million corresponding to the step acquisition of Felix, and a prior year indexation adjustment of Stabilization Fund receivables at AES Andes of $12 million, as well as a $10 million decrease in insurance proceeds and a $7 million decrease in AFUDC at our U.S. utilities in the current year. This was partially offset by a $10 million gain at AES Andes in the current year corresponding to the write-off of contingent consideration for a renewables development project determined to be no longer viable.
Other expense
Other expense increased $283 million to $458 million in 2025, compared to $175 million in 2024 primarily driven by $159 million higher losses on commencement of sales-type leases at AES Clean Energy and AES Renewable Holdings, a $74 million increase in losses on remeasurement of contingent consideration primarily on projects acquired at AES Clean Energy, and a $48 million current year loss on remeasurement of our investment in 5B, accounted for using the measurement alternative; partially offset by a $20 million loss recognized in the prior year related to legal expenses and other direct costs associated with the troubled debt restructuring at Puerto Rico.
See Note 22— Other Income and Expense included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Gain on disposal and sale of business interests
Gain on disposal and sale of business decreased $293 million to $58 million in 2025, compared to $351 million in 2024. This decrease was primarily due to the prior year gain on sale of AES Brasil of $312 million and a $52 million gain in the prior year on dilution of AES' ownership interest in Uplight as a result of the AutoGrid acquisition. This was partially offset by a $70 million gain on the sell-down of Dominican Republic Renewables, which is now accounted for as an equity method investment.
See Note 9— Investments in and Advances to Affiliates and Note 25— Held-for-Sale and Dispositions included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Asset impairment expense
Asset impairment expense decreased $150 million, or 40%, to $224 million in 2025, compared to $374 million in 2024. This decrease was primarily due to a $243 million increase in the carrying value of the Mong Duong asset group due to the derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 and the elimination of net estimated costs to sell upon reclassifying Mong Duong from held-for-sale to held and used, and lower impairment expense of $45 million at Mong Duong and prior year impairments of $125 million and $80 million at Ventanas and AES Brasil, respectively, associated with the held-for-sale classification. This was partially offset by a $264 million impairment at Maritza due to a reduction in expected cash flows after the expiration of the current PPA, and higher impairment expense of $62 million and $16 million at AES Clean Energy Development and AES Andes, respectively, due to the write-off of project development intangibles and capitalized development costs for projects that were determined to be no longer viable, including $51 million at AES Clean Energy Development due to the right sizing of our development company as part of the restructuring program initiated in February 2025.
See Note 23— Asset Impairment Expense included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
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Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
Years Ended December 31,
Chile
Argentina
Corporate
Other
Total (1)
(1) Includes losses of $26 million and gains of $137 million on foreign currency derivative contracts for the years ended December 31, 2025 and 2024, respectively.
The Company recognized net foreign currency transaction losses of $79 million in 2025, primarily driven by unrealized losses due to the depreciation of the Argentine peso, and unrealized losses in Chile due to the appreciation of the Chilean peso and the appreciation of the Colombian peso, which negatively impacted foreign currency forwards.
The Company recognized net foreign currency transaction gains of $31 million in 2024, primarily driven by realized gains on swaps and options denominated in the Brazilian real.
Other non-operating expense
Other non-operating expense was $113 million in 2025 due to a $103 million impairment of the Uplight equity method investment and convertible notes as a result of observable market factors; and a $10 million other-than-temporary impairment of convertible notes for 5B as a result of an observable price change from a transaction between 5B and a third party.
See Note 9— Investments In and Advances to Affiliates included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Income tax benefit (expense)
Income tax benefit was $181 million in 2025 compared to income tax expense of $59 million in 2024. The Company's effective tax rates were (241)% and 7% for the years ended December 31, 2025 and 2024, respectively.
The 2025 effective tax rate was impacted by the current year benefits associated with ITCs and the reclassification of the Mong Duong asset group as held and used from held-for-sale, partially offset by the impacts of allocations of losses to tax equity investors on renewables projects. The 2024 effective tax rate was impacted by the prior year benefits associated with ITCs and the restructuring of a foreign holding company. These drivers were partially offset by the impacts of allocations of losses to tax equity investors on renewables projects. See Note 23— Asset Impairment Expense included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the Mong Duong reclassification.
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. Foreign earnings may be taxed at rates higher than the U.S. corporate rate of 21% and are also subject to current U.S. taxation under the GILTI rule. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. The Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments regarding employment and capital investment. See Note 24— Income Taxes included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for additional information regarding these reduced rates.
Net equity in losses of affiliates
Net equity in losses of affiliates increased $29 million to $55 million in 2025, compared to $26 million in 2024. This increase was primarily driven by lower earnings from sPower of $31 million, mainly due to lower contributions from renewables projects that came online.
See Note 9— Investments In and Advances to Affiliates included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
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Loss from disposal of discontinued businesses
Net loss from disposal of discontinued businesses was $39 million in 2025, compared to $7 million in 2024, primarily related to alleged damages plus interest, as well as potential future damages, under a dispute related to representations and warranties in the 2016 share purchase agreement for Sul in the current year.
See Note 31— Discontinued Operations included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Net income (loss) attributable to noncontrolling interests and redeemable stock of subsidiaries
Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $129 million, or 15%, to $748 million in 2025, compared to $877 million in 2024. This decrease was primarily due to a decrease of $149 million at Mong Duong mostly driven by the derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 upon reclassifying Mong Duong from held-for-sale to held and used, a decrease of $135 million at AES Clean Energy primarily attributable to lower allocation of losses to tax equity investors on projects placed in service and increased development services in the U.S., $34 million related to the sale of AES Brasil, $25 million related to improved operating results at Southland Energy after maintenance in the prior year, and $23 million related to the sell-down of AGIC. This was partially offset by an increase of $150 million at AES Indiana primarily attributable to higher allocation of losses to tax equity investors on BESS projects placed in service, $55 million due to day-one losses on the commencement of sales-type leases at AES Clean Energy Development, and $25 million related to acquisition of the remaining common shares in Cochrane.
Net income (loss) attributable to The AES Corporation
Net income attributable to The AES Corporation decreased $769 million, or 46%, to $910 million in 2025, compared to $1,679 million in 2024. This decrease was primarily due to:
• The prior year gain on sale of AES Brasil of $312 million;
• Lower margins from the Energy Infrastructure SBU of $271 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 net derivative gains as part of our commercial hedging strategy;
• Higher other expense of $211 million primarily related to day-one losses on commencement of sales-type leases and remeasurement of contingent consideration at AES Clean Energy Development;
• Higher impairments of $264 million at Maritza due to a reduction in expected cash flows after the expiration of the current PPA, partially offset by a $125 million prior-year impairment at Ventanas;
• Other non-operating expense of $113 million due to an impairment of the Uplight equity method investment and convertible notes, as well as an other-than-temporary impairment of convertible notes for 5B;
• Higher foreign currency translation losses of $102 million primarily related to unrealized losses due to the depreciation of the Argentine peso and unrealized losses in Chile due to the appreciation of the Chilean peso and the appreciation of the Colombian peso;
• Lower other income of $73 million primarily related to the prior year recognition of a bargain purchase gain on the Madison and Birdseye acquisition, a prior year gain corresponding to the step acquisition of Felix, and a prior year indexation adjustment of Stabilization Fund receivables at AES Andes;
• Lower interest income of $55 million primarily related to the sale of AES Brasil and prior year interest recognized on Stabilization Fund receivables in Chile; and
• One-time restructuring costs of $51 million.
These drivers were partially offset by:
• Higher income tax benefit of $257 million due to a lower effective tax rate, mainly driven by tax credit transfers;
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• Higher margins from the Renewables SBU of $144 million, excluding one-time restructuring costs, primarily due to increases from new businesses and development services in the U.S., increased availability and lower spot prices on energy purchases in Colombia, and better hydrology in Colombia and Panama, partially offset by the negative impact of the sale of AES Brasil; and
• Derecognition of a valuation allowance on the loan receivable accounted for under ASC 310 upon reclassifying Mong Duong from held-for-sale to held and used of $127 million; and
• Higher margins from the Utilities SBU of $48 million, excluding one-time restructuring costs, primarily due to higher retail rates as a result of the AES Indiana 2024 Base Rate Order and AES Ohio 2024 DRC Settlement, higher transmission rates and rider revenues, and higher demand due to the impact of weather.
SBU Performance Analysis
Segments
We are organized into four technology-based SBUs: Renewables (solar, wind, energy storage, and hydro generation facilities); Utilities (AES Indiana, AES Ohio, and AES El Salvador regulated utilities and their generation facilities); Energy Infrastructure (natural gas, LNG, coal, pet coke, diesel, and oil generation facilities); and New Energy Technologies (investments in Fluence, Maximo, and other new and innovative energy technology businesses). Prior to the first quarter of 2025, our businesses in Chile 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.
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 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 increase to Adjusted EBITDA of $22 million for the year ended December 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.
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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 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 represent 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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Years Ended December 31,
Reconciliation of Adjusted EBITDA and Adjusted EBITDA with Tax Attributes (in millions)
Net income
Income tax expense (benefit)
Interest expense
Interest income
Depreciation, amortization, and accretion of AROs
EBITDA
Less: Loss from disposal of discontinued businesses
Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1)
Less: Income tax expense (benefit), interest expense (income), and depreciation, amortization, and accretion of AROs from equity affiliates
Interest income recognized under service concession arrangements
Unrealized derivatives, equity securities, and financial assets and liabilities losses (gains)
Unrealized foreign currency losses
Disposition/acquisition losses (gains)
Impairment losses
Loss on extinguishment of debt and troubled debt restructuring
Restructuring costs
Adjusted EBITDA (1)
Tax attributes
Adjusted EBITDA with Tax Attributes (2)
(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 attributable to noncontrolling interests and redeemable stock of subsidiaries on the 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.
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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 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 the Corporate segment, 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 of affiliates .
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to The AES Corporation . We believe that Adjusted PTC better reflects the underlying business performance of the Company and is a relevant measure considered in the Company's internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses pertaining to derivative transactions, equity securities, or financial assets and liabilities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, and strategic decisions to dispose of or acquire business interests, retire debt, 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 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.
Years Ended December 31,
Reconciliation of Adjusted PTC (in millions)
Income from continuing operations, net of tax, attributable to The AES Corporation
Income tax expense (benefit) attributable to The AES Corporation
Pre-tax contribution
Unrealized derivatives, equity securities, and financial assets and liabilities losses (gains)
Unrealized foreign currency losses
Disposition/acquisition losses (gains)
Impairment losses
Loss on extinguishment of debt and troubled debt restructuring
Restructuring costs
Total Adjusted PTC
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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 a relevant measure 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, and 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 $1.31 for the year ended December 31, 2025. 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 and increased by decreases in the carrying amount to the extent they represent recoveries of amounts previously reflected in the computation of earnings per share. While the adjustment for the year ended December 31, 2025 decreased earnings per share, it did not impact Net income on the 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.
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Reconciliation of Numerator Used for Adjusted EPS
Year Ended December 31, 2025
(in millions, except per share data)
Income
Shares
$ per Share
GAAP DILUTED EARNINGS PER SHARE
Income from continuing operations available to The AES Corporation common stockholders
Add back: Increase in redemption value of redeemable stock of subsidiaries
NON-GAAP DILUTED EARNINGS PER SHARE BEFORE EFFECT OF DILUTIVE SECURITIES
Restricted stock units
NON-GAAP DILUTED EARNINGS PER SHARE
Years Ended December 31,
Reconciliation of Adjusted EPS
Diluted earnings per share from continuing operations
Unrealized derivatives, equity securities, and financial assets and liabilities losses (gains)
Unrealized foreign currency losses
Disposition/acquisition losses (gains)
Impairment losses
Loss on extinguishment of debt and troubled debt restructuring
Restructuring costs
Less: Net income tax benefit
Adjusted EPS
(1) Amount primarily relates to remeasurement of our investment in 5B of $48 million, or $0.07 per share, and net unrealized derivative losses at the Energy Infrastructure SBU of $41 million, or $0.06 per share.
(2) Amount primarily relates to unrealized gains on cross currency swaps in Brazil of $39 million, or $0.05 per share, unrealized gains on commodity derivatives at AES Clean Energy of $38 million, or $0.05 per share, and net unrealized derivative gains at the Energy Infrastructure SBU of $25 million, or $0.04 per share.
(3) Amount primarily relates to day-one losses on commencement of sales-type leases at AES Clean Energy Development of $166 million, or $0.23 per share, and AES Renewable Holdings of $13 million, or $0.02 per share, and losses on remeasurement of contingent consideration at AES Clean Energy of $66 million, or $0.09 per share; partially offset by gain on sale of Dominican Republic Renewables of $45 million, or $0.06 per share, and write-off of contingent consideration for a renewables development project at AES Andes of $10 million, or $0.01 per share.
(4) Amount primarily relates to gain on sale of AES Brasil of $312 million, or $0.44 per share, a gain on dilution of ownership in Uplight due to its acquisition of AutoGrid of $53 million, or $0.07 per share, and realized gains on cross currency swaps hedging the AES Brasil sale proceeds of $34 million, or $0.05 per share; partially offset by day-one losses at commencement of sales-type leases at AES Renewable Holdings of $63 million, or $0.09 per share, and loss on partial sale of our ownership interest in Amman East and IPP4 in Jordan of $10 million, or $0.01 per share.
(5) Amount primarily relates to impairments at Maritza of $264 million, or $0.37 per share, at Uplight of $103 million, or $0.14 per share, related to an impairment of the equity method investment and convertible notes, at AES Clean Energy Development projects of $80 million, or $0.11 per share, impairments at a renewables development project at AES Andes of $16 million, or $0.02 per share, and at Mong Duong of $9 million, or $0.01 per share; partially offset by the derecognition of the valuation allowance on a loan receivable accounted for under ASC 310 and the elimination of estimated costs to sell at Mong Duong of $127 million, or $0.18 per share, after reclassification to held and used.
(6) Amount primarily relates to impairments at Ventanas of $125 million, or $0.18 per share, at AES Clean Energy Development projects of $70 million, or $0.10 per share, at Brazil of $38 million, or $0.05 per share, and at Mong Duong of $32 million, or $0.04 per share.
(7) Amount primarily relates to losses incurred at AES Andes due to early retirement of debt of $29 million, or $0.04 per share, and costs incurred due to troubled debt restructuring at Puerto Rico of $20 million, or $0.03 per share.
(8) Amount relates to severance costs associated with the Company-wide restructuring program of $51 million, or $0.07 per share, and impairments at AES Clean Energy Development that were the result of the Company’s restructuring program of $38 million, or $0.05 per share.
(9) Amount primarily relates to income tax benefits associated with the day-one losses on commencement of sales-type leases primarily at AES Clean Energy Development of $41 million, or $0.06 per share, valuation allowance related to Uplight impairment of the equity method investment and convertible notes of $39 million, or $0.05 per share, impairments at AES Clean Energy Development projects of $27 million, or $0.04 per share, remeasurement of contingent consideration at AES Clean Energy of $15 million, or $0.02 per share, impairments at Maritza of $12 million, or $0.02 per share, severance costs related to the Company's restructuring program of $10 million, or $0.01 per share, net unrealized derivative losses at AES Integrated Energy of $6 million, or $0.01 per share, and remeasurement of our investment in 5B of $4 million, or $0.01 per share; partially offset by income tax expense associated with the AES Ohio sell-down of $13 million, or $0.02 per share.
(10) Amount primarily relates to income tax benefits associated with the impairment and tax over book investment basis difference related to AES Ventanas of $68 million, or $0.09 per share, the sale of AES Brasil of $18 million, or $0.02 per share, the impairment at AES Clean Energy Development projects of $16 million, or $0.02 per share, and the day-one losses on commencement of sales-type leases at AES Renewable Holdings of $13 million, or $0.02 per share.
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Renewables SBU
The following table summarizes Operating Margin, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes (in millions) for the periods indicated:
For the Years Ended December 31,
$ Change
% Change
Operating Margin
Adjusted EBITDA (1)
Adjusted EBITDA with Tax Attributes (1)
(1) A non-GAAP financial measure. See S BU Performance Analysis—Non-GAAP Measures for definition and Item 1. — Business for the respective ownership interest for key businesses.
Operating Margin increased $104 million, primarily driven by $91 million due to development services in the U.S., $89 million from new businesses, $68 million in Colombia as a result of increased availability and lower spot prices on energy purchases, $60 million due to the results of AES Andes moving to Renewables in 2025, and $36 million due to higher generation in Panama as a result of better hydrological conditions during the first quarter of 2025. These increases were partially offset by a $177 million decrease due to the sale of AES Brasil in 2024, a $42 million decrease related to changes in mark-to-market of energy derivatives, a $38 million increase in fixed costs primarily related to an accelerated growth plan, and $15 million of one-time costs due to restructuring.
Adjusted EBITDA increased $320 million primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, restructuring costs, and depreciation, as well as higher Adjusted EBITDA from equity affiliates.
Adjusted EBITDA with Tax Attributes increased $401 million, primarily due to the increase in Adjusted EBITDA explained above, and higher tax attributes realized in the current year due to timing of tax attribute recognition, including higher income from tax credit transfers. During the years ended December 31, 2025 and 2024, we realized $1,374 million and $1,293 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:
For the Years Ended December 31,
$ Change
% Change
Operating Margin
Adjusted EBITDA (1)
Adjusted EBITDA with Tax Attributes (1)
Adjusted PTC (1) (2)
(1) A non-GAAP financial measure. See S BU Performance Analysis—Non-GAAP Measures for definition and Item 1. — Business for the respective ownership interest for key businesses.
(2) Adjusted PTC remains a key metric used by management for analyzing our businesses in the utilities industry .
Operating Margin increased $92 million, primarily driven by $191 million due to higher retail rates as a result of the AES Indiana 2024 Base Rate Order and AES Ohio 2024 DRC Settlement, including the impact of certain riders now incorporated into base rates, higher transmission and rider revenues, and higher demand due to the impact of weather. These increases were partially offset by a $46 million increase in depreciation and amortization expense from additional assets placed in service, a $33 million increase in fixed costs mainly driven by higher property taxes due to higher assessed values, and a $14 million decrease due to the impact of planned outages.
Adjusted EBITDA increased $71 million primarily due to the drivers mentioned above, adjusted for NCI, depreciation and amortization, and restructuring costs.
Adjusted EBITDA with Tax Attributes increased $217 million mainly driven by a $146 million increase in realized tax attributes primarily related to the Pike County BESS and Petersburg Energy Center projects in the current year, as well as the increase in Adjusted EBITDA explained above.
Adjusted PTC increased $197 million primarily due to the drivers above, partially offset by higher depreciation and amortization expense.
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Energy Infrastructure SBU
The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated:
For the Years Ended December 31,
$ Change
% Change
Operating Margin
Adjusted EBITDA (1)
(1) A non-GAAP financial measure. See S BU Performance Analysis—Non-GAAP Measures for definition and Item 1. — Business for the respective ownership interest for key businesses.
Operating Margin decreased $332 million, primarily driven by $160 million higher prior year revenues from the monetization of the Warrior Run coal plant PPA, $108 million due to prior year unrealized and realized derivative gains, $60 million of prior year operating margin at AES Andes, which is reported in the Renewables SBU beginning in 2025, $23 million of lower LNG sales net of higher terminal fees, $18 million of one-time costs due to restructuring, and $17 million due to the prior year sell-down of Amman East and IPP4 in Jordan; partially offset by an increase of $49 million driven by higher availability due to lower maintenance in 2025.
Adjusted EBITDA decreased $176 million, primarily due to the drivers above, adjusted for unrealized derivatives and restructuring costs, as well as higher realized foreign currency gains; partially offset by the increase in ownership of Cochrane and higher equity earnings due to Gatun starting commercial operations.
New Energy Technologies SBU
The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated:
For the Years Ended December 31,
$ Change
% Change
Operating Margin
Adjusted EBITDA (1)
(1) A non-GAAP financial measure. See S BU Performance Analysis—Non-GAAP Measures for definition and Item 1. — Business for the respective ownership interest for key businesses.
Operating Margin decreased $4 million, with no material drivers.
Adjusted EBITDA increased $3 million, primarily due to a $23 million decrease in general and administrative expenses mainly related to lower business development costs, and lower losses from Uplight of $10 million after equity method accounting was suspended in the fourth quarter of 2025; partially offset by higher net losses from Fluence of $26 million mainly driven by a decline in sales, reflecting lower volumes fulfilled due to the timing of customer schedules.
Key Trends and Uncertainties
During 2026 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.— Business and Item 1A.— Risk Factors of this 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/CVD duties on certain imported cells and panels from Southeast Asia. Commerce’s determination and related matters remain the subject
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of ongoing litigation before the U.S. Court of International Trade ("CIT") and the U.S. Court of Appeals for the Federal Circuit.
In 2024, Commerce and the U.S. International Trade Commission (“ITC”) initiated new AD/CVD investigations on solar cells and panels imported from Southeast Asia. On April 18, 2025, Commerce rendered final affirmative determinations and AD/CVD rates with respect to all four countries. On June 13, 2025, the ITC issued its determination that imports from Malaysia and Vietnam have injured the U.S. industry and that imports from Cambodia and Thailand threaten injury. Commerce then issued orders on June 24, 2025, implementing the AD/CVD rates, which will be subject to annual review by Commerce. There is ongoing litigation about these and related matters in the CIT. We do not expect these AD/CVD orders will have a negative impact on our business.
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 expired 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 tariffs currently set at 25% effective January 1, 2026 (an increase from the previous rate of 7.5%). There are also ongoing AD/CVD investigations with respect to exports by China of natural and synthetic graphite used to make lithium-ion battery anode material. Final ITC and Commerce AD/CVD determinations in these investigations are expected in the first quarter of 2026 and 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 tariffs under Section 232 of the Trade Expansion Act of 1962 ("Section 232") on steel and aluminum imports to expand their scope and impose 25% tariffs on both products. The President raised these rates to 50% effective June 4, 2025. 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”) with respect to U.S. importation of fentanyl. The President imposed 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, which was later extended until August 1, 2025. Effective May 14, 2025, the IEEPA reciprocal tariff rate applicable to China was lowered to 10%. IEEPA reciprocal tariffs, at various levels, have now gone into effect for most U.S. trading partners.
Several trading partners (including the EU, Japan, South Korea, and the UK) have reached bilateral trade agreements or frameworks with the U.S. The ultimate outcome of any reciprocal or other tariffs with countries that have not yet reached such trade agreements with the U.S. is uncertain. Also, in February 2026, on review of lower court decisions declaring the tariffs unlawful, the Supreme Court issued a decision holding that IEEPA does not authorize tariffs. However, President Trump subsequently stated that new tariffs would be issued under different statutory authority. The impact of these potential new tariffs on the Company is uncertain.
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In July 2025, Commerce initiated a Section 232 investigation to determine the effects on national security of imports of polysilicon and its derivatives. In August 2025, Commerce initiated a separate investigation under Section 232 to determine the effects on national security of imports of wind turbines and their parts and components. These investigations are ongoing and their outcomes are uncertain.
In January 2026, the President issued a Proclamation under Section 232 concerning the importation of several critical minerals (including graphite and lithium) from any country. The Proclamation does not impose tariffs on the critical minerals but directs Commerce and the U.S. Trade Representative to negotiate agreements with foreign partners to secure reliable access to the critical minerals. An update on the outcome or status of these negotiations must be provided to the President within 180 days of the Proclamation. If the negotiations fail to result in agreements or to adequately address the identified risks, the President may consider trade-restrictive measures with respect to the critical minerals. The outcome of this process as well as its potential impact on the Company are uncertain.
We expect the tariffs on imports from China will increase overall costs for materials and parts that are imported to build and maintain renewable energy plants for the U.S. industry. However, AES has already shifted its supply chain outside of China for the vast majority of final products used to build and maintain renewable energy plants in the U.S. We expect limited impact to projects scheduled to become operational in 2026 through 2027 due to the announced tariffs on China.
The impact of new tariffs, reciprocal tariffs, or U.S. Government investigations or proclamations, the impact of any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, the potential future disruptions to the renewable energy supply chain and their effect on AES’ U.S. project development and construction activities remain uncertain. AES will continue to monitor developments and take prudent steps towards maintaining a robust supply chain for our renewable energy projects. To that end, we have accelerated imports into the U.S. and increased our contracting for U.S. domestically manufactured solar panels, batteries, wind turbines, trackers, and other equipment, significantly mitigating the potential impacts from reciprocal tariffs or other tariffs.
For our U.S backlog of solar projects scheduled to finish construction and become operational in 2026 or 2027, we have contracted for most of our panel supply needs, with the majority of such panels being manufactured in the U.S. and most of the remaining panels having already been imported into the U.S. These remaining imports are expected to be largely insulated from AD/CVD measures and potential Section 232 outcomes, as they are expected to be manufactured using U.S. polysilicon. Imports will exclude modules from countries currently subject to AD/CVD orders or investigations.
Additionally, for our U.S. backlog of storage projects scheduled to finish construction and become operational in 2026 or 2027, we have contracted all our battery needs, with almost all of such batteries coming from U.S. or Korean suppliers. We have also completed contracting of U.S. domestically manufactured battery modules to support the remainder of our U.S. energy storage growth through 2027.
For our U.S. backlog of wind projects scheduled to be completed in 2026, we have contracted and received delivery of all turbines, and for our 2027 backlog of U.S. wind projects, we are fully contracted with U.S. suppliers and suppliers with primarily U.S. manufactured turbines.
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.
La Niña conditions emerged towards the end of 2025 in the equatorial Pacific, following a period of ENSO-neutral conditions earlier in the year. According to the Climate Prediction Center (“CPC”) and the International Research Institute for Climate and Society (“IRI”), La Niña began to dissipate in January 2026. Forecasts point to a transition back to ENSO-neutral conditions in early 2026 (through March 2026).
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In Panama, total 2025 system inflows remained near historical averages, with the Bayano and Fortuna reservoirs however experiencing above-average levels due to abundant rainfall in the northern basins. These favorable conditions have supported strong hydroelectric generation, reduced reliance on thermal generation, and enabled potential surplus energy sales into the spot market. Furthermore, the commissioning of the Gatun combined cycle gas power plant by mid-2025 significantly reduced price and volatility, due to the displacement of other thermal generation. Additionally, the lower dispatch of natural gas-fired units due to favorable hydrology may create strategic opportunities for gas reallocation to international markets.
In Colombia, 2025 was the second wettest year on record. Reservoir levels remained elevated through Q4, with Chivor and other major reservoirs above seasonal norms. The favorable system hydrology throughout the year drove down spot prices compared to the prior year. Although, the fourth quarter saw a slight decline in rainfall and a moderate rise in spot prices, overall system storage remained robust.
In Chile, 2025 ranked as the fifth driest on record; however, it was marked by a structural decoupling of hydrology and the energy matrix. The power system demonstrated unprecedented resilience by offsetting the decline in hydroelectricity with record-breaking solar and wind generation, while leveraging the accelerated integration of BESS to mitigate curtailment, stabilize prices, and compensate for depleted system reservoirs.
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
The macroeconomic and political environments in some countries where our subsidiaries conduct business have changed during 2025. This could result in significant impacts to tax laws and environmental and energy policies. Additionally, we operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level. See Item 7A.— Quantitative and Qualitative Disclosures About Market Risk for further information.
U.S. Tax Law Reform and U.S. Renewable Energy Tax Credits — On July 4, 2025, the U.S. enacted H.R. 1 (the “2025 Act”). The legislation significantly revised the laws governing U.S. renewable energy tax credits and the U.S. taxation of certain foreign earnings, which may impact our effective tax rate in future periods and could be material. In addition, the 2025 Act included amendments to, and extensions of, various other U.S. corporate income tax provisions including the determination of limitation on interest expense deductions. Any impact may change as U.S. Treasury and Internal Revenue Service (“IRS”) issue additional guidance, which may be material.
The U.S. Inflation Reduction Act of 2022 (the “IRA”) included provisions that benefited the U.S. clean energy industry, including increases, extensions, direct transfers, and/or new tax credits for onshore and offshore wind, solar, storage, and hydrogen projects. We account for U.S. renewables projects according to U.S. GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the value of the tax credit that benefits the tax equity investors at the time of its creation, which for projects utilizing the investment tax credit, begins in the quarter the renewables project is placed in service. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy.
The 2025 Act amends the phase out of wind and solar ITC and PTC tax credits. Wind and solar renewables projects that begin construction within 12 months of the enactment of the 2025 Act remain eligible for 100% of the credit without the 2027 placed-in-service deadline, provided that, under current Treasury guidance, the projects are placed in service no more than four calendar years after the calendar year when construction began. Wind and solar projects that begin construction after 12 months of the enactment must be placed in service no later than 2027. Wind and solar projects that began construction by the end of 2024 are not impacted by the 2025 Act. The 2025 Act does not impose tighter timelines for energy storage projects to qualify for the ITC and PTC, and it allows energy storage projects to receive the full ITC or PTC credit if they begin construction by 2033.
The 2025 Act also imposes a restriction precluding credits for renewables and storage projects claiming the ITC or PTC credit that start construction after December 31, 2025 and receive material assistance from a prohibited foreign entity, effectively limiting the percentage of total project costs that may be derived from products that are mined, produced or manufactured in China, with varying permissible percentages depending on the calendar year
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and applicable technology for the project. This restriction also precludes credit eligibility for taxpayers owning projects that start construction after December 31, 2024 that are classified as having ownership or certain other interests by a prohibited foreign entity, including projects over which a prohibited foreign entity is deemed to exercise formal or effective control.
Further, President Trump issued an Executive Order on July 7, 2025 that directed the Secretary of the Treasury to take action to enforce the provisions of the 2025 Act related to issuing updated guidance defining the start of construction for claiming the ITC and PTC and implementing the Foreign Entity of Concern (“FEOC”) Restrictions (the “Treasury Action”). The Executive Order also directed the Secretary of the Interior to take action to review its regulations, guidance, policies, and practices for any preferential treatment of wind and solar projects and eliminate those preferences within 45 days (the “Interior Action”).
On August 15, 2025, the Department of Treasury issued updated guidance defining the start of construction for purposes of claiming the ITC and PTC. AES does not expect the modifications to the start of construction guidance to materially impact its projects. The Department of Treasury has not yet issued comprehensive guidance implementing the FEOC restrictions, however. Further guidance, which may be material, is expected to be released within the coming months.
We expect the vast majority of our renewables project backlog to continue to qualify for the ITC and PTC. However, the Treasury Action may impose additional burdens in qualifying for the ITC and PTC.
In response to the Executive Order, the Department of Interior issued a memorandum requiring any “decisions, actions, consultations, and other undertakings” for wind or solar projects under Department of Interior jurisdiction to go through an additional three-phase approval process ending with approval from the Secretary of the Interior.
Our U.S. wind and solar projects are developed primarily on private land and are designed in a manner that minimizes the potential of a federal nexus. However, due to the broad language of the memorandum, there may be some impact to projects developed on private land.
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 recognized $1,540 million of earnings from Tax Attributes, comprised of $1,374 million from the Renewables SBU and $166 million from the Utilities SBU.
The enactment of the 2025 Act requires that substantial guidance be published by the U.S. Department of Treasury and other government agencies. While we have taken significant measures to protect against the impact of changes under the 2025 Act to the IRA, including by implementing a program designed to ensure our backlog of U.S. renewables projects satisfy IRS safe harbor requirements for qualifying for the ITCs and PTCs, the impacts of the 2025 Act, the Treasury Action, the Interior Action or future actions that have the effect of modifying or repealing the ITCs and PTCs or adversely impacting renewable energy projects may be material to our results of operations.
Net CFC Tested Income (“NCTI”) — The 2025 Act amended the Global Intangible Low-Taxed Income (“GILTI”) provision by eliminating the reduction to foreign earnings subject to GILTI by an allowable economic return on investment beginning January 1, 2026. The GILTI provision was also renamed to the NCTI provision. Additionally, the 2025 Act modified the U.S. foreign tax credit provisions beginning January 1, 2026. Although the new NCTI rules provide for a reduced 14 percent effective tax rate on captured foreign income, by way of a 40 percent deduction, companies with a U.S. net operating loss or otherwise insufficient taxable income will not benefit from the lower effective tax rate and may not be able to utilize foreign tax credits. The new NCTI rules may subject a portion of our foreign earnings to current U.S. taxation in the future and could be material.
Limitation on Interest Expense Deductions — The 2025 Act retroactively amended the existing limitation on the deductibility of net interest expense beginning January 1, 2025. As amended, the deduction will be limited to interest income, plus 30% of tax basis EBITDA. Previously, the limitation was based on 30% of tax basis Earnings Before Interest and Taxes (“EBIT”). We expect the amendment to increase the current period permitted interest deductions and reduce the amount of disallowed interest expense subject to an indefinite carryforward. The limitation continues to be inapplicable to interest expense attributable to regulated utility property.
Global Tax — The macroeconomic and political environments in the U.S. and in some countries where our subsidiaries conduct business have changed in recent years. This could result in significant impacts to future tax law. In the U.S., the IRA included a 15% corporate alternative minimum tax (“CAMT”) based on adjusted financial statement income. In June 2025, the IRS began releasing interim guidance for CAMT and announced its intention to revise regulations that were proposed in September 2024. The impact to the Company in 2025 is not material. We will continue to monitor the issuance of CAMT revised guidance.
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The Netherlands, Bulgaria, and Vietnam adopted legislation to implement Pillar 2 effective as of January 1, 2024. On January 5, 2026, the OECD published a side-by-side package to modify the Pillar 2 system in a manner that will fully exclude domestic and foreign profits of US-parented groups from Pillar 2’s Undertaxed Profits Rule and Income Inclusion Rule. The side-by-side package is intended to take effect as of January 1, 2026, but is subject to enactment of legislation in the local jurisdictions. We will continue to monitor the issuance of legislation incorporating the side-by-side package, as well as other Pillar 2 amendments and new interpretive guidance in non-EU countries where the Company operates.
Inflation — In the markets in which we operate, there have been higher rates of inflation recently. While most of our contracts in our international businesses are indexed to inflation, in general, our U.S.-based generation contracts are not indexed to inflation. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may also increase the costs of some of our development projects that could negatively impact their competitiveness. Our utility businesses allow for recovery of O&M costs through the regulatory process, which may have timing impacts on recovery.
Interest Rates — In the U.S. and other markets in which we operate, there has been a rise in interest rates during 2021 through 2023, and interest rates are expected to remain volatile in the near term. As discussed in Item 7A.— Quantitative and Qualitative Disclosures about Market Risk , although most of our existing corporate and subsidiary debt is at fixed rates, an increase in interest rates can have several impacts on our business. For any existing debt under floating rate structures and any future debt refinancings, rising interest rates will increase future financing costs. In most cases in which we have floating rate debt, our revenues serving this debt are indexed to inflation which helps mitigate the impact of rising rates. For future debt refinancings, AES actively manages a hedging program to reduce uncertainty and exposure to future interest rates. For new business, higher interest rates increase the financing costs for new projects under development and which have not yet secured financing.
AES typically seeks to incorporate expected financing costs into our new PPA pricing such that we maintain our target investment returns, but higher financing costs may negatively impact our returns or the competitiveness of some of our development projects. Additionally, we typically seek to enter into interest rate hedges shortly after signing PPAs to mitigate the risk of rising interest rates prior to securing long-term financing.
Argentina — In July 2024, the Argentine government enacted Law 27,742, known as Ley Bases, declaring a one-year public emergency in administrative, economic, financial, and energy matters. It grants the President delegated powers and initiates broad state reforms to deregulate the economy, including labor reform, the Incentive Regime for Large Investments, modifications to non-income tax measures, and the privatization of state-owned energy companies. Additionally, the Ministry of Energy issued Resolution 150/2024, repealing certain regulations from previous years that involved excessive state and CAMMESA intervention in the Wholesale Electricity Market (“MEM”).
On January 28, 2025, the Energy Secretariat issued Resolution 21/2025 to reform the MEM and is intended to ensure secure energy supply and stable consumer costs.
On April 11, 2025, the Central Bank of Argentina started a new economic program supported by a $20 billion agreement with the International Monetary Fund. The key points of the program include (a) a removal of exchange restrictions for individuals and (b) foreign shareholders can distribute profits starting from 2025 and deadlines for foreign trade payments are relaxed.
On July 4, 2025, the Argentine government issued Decree 450/25, initiating a 24-month transition period to reform and deregulate the country’s electricity market. The decree encourages free contracting between private entities and fosters competition in electricity generation and commercialization. Subsequently, on October 20, 2025, the Ministry of Economy and the Secretariat of Energy issued Resolution 400/25, which became effective on November 1, 2025, and provides a new framework introducing more competitive price signals, decentralizing fuel management, and reducing subsidies.
These changes may have a profound impact on the sector, influencing our operations and financial results. It is not yet possible to predict the impact of these regulations in our consolidated results of operations, cash flows, and financial condition.
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Puerto Rico — Our subsidiaries in Puerto Rico have long-term PPAs with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico.
The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was enacted to create a structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). PROMESA also expedites the approval of key energy projects and other critical projects in Puerto Rico. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.
PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Ilumina’s non-recourse debt of $20 million continues to be in technical default and is classified as current as of December 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. The mediation period was subsequently extended through April 1, 2026, reflecting the continuing efforts to resolve remaining matters under the Title III proceedings.
Considering the information available as of the date hereof, management believes the carrying amount of our long-lived assets in Puerto Rico of $80 million is recoverable as of December 31, 2025.
Impairments and Realizability
Long-lived Assets and Current Assets Held-for-Sale — During the year ended December 31, 2025, the Company recognized asset impairment expense of $224 million. See Note 23— Asset Impairment Expense included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information. As of December 31, 2025, after recognizing these impairment expenses, the carrying value of our investments in long-lived assets and current assets held-for-sale that were assessed for impairment following a triggering event in 2025 was $109 million.
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 $243 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.
Regulatory
FERC, RTOs, and Interconnection Prioritization — FERC approved one-time queue jumping proposals in PJM, MISO, and SPP over the course of the year. Limited additions to each RTO’s queue are not expected to materially impact the projects already in our backlog; however, they could create uncertainty around network upgrade costs and the timing of integration of future projects in each RTO’s queue. See Item 1A.— Risk Factors — Our development projects are subject to substantial uncertainties included in this Form 10-K for further details.
AES Ohio Legislation and Three-Year Rate Plan — On April 30, 2025, the Ohio legislature passed new energy legislation (House Bill 15) that was signed by the Governor and became effective August 14, 2025. The legislation allows Ohio’s electric utilities to file three-year forecasted base distribution rate cases, which would
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replace electric security plans (ESPs) and associated recovery riders. AES Ohio currently anticipates that remaining recovery rider balances would be included in future base rates. Among other provisions, the legislation eliminates as of its effective date, the LGR, which previously allowed for recovery of net OVEC costs and revenues. Changes to the regulatory framework from this legislation, including the recovery of future net OVEC costs and revenues or remaining recovery rider balances, could be material to our results of operations, financial condition, and cash flows. To comply with House Bill 15, AES Ohio filed an application with the PUCO on November 10, 2025 to establish a Three-Year Rate Plan. This plan describes the investments necessary to strengthen and modernize AES Ohio's infrastructure and expand support for its customers. To enable these ongoing investments, the application also proposes rates for future electric distribution service in 2027, 2028, and 2029. The PUCO has set the evidentiary hearing to begin August 4, 2026, and a Commission Order is anticipated by the end of 2026.
AES Ohio ESP Appeal — From November 1, 2017 through December 18, 2019, AES Ohio operated pursuant to an approved ESP plan, which was initially approved on October 20, 2017 (ESP 3). On December 18, 2019, the PUCO approved AES Ohio's Notice of Withdrawal of ESP 3 and reversion to its prior rate plan (ESP 1). Among other items, the PUCO Order approving the ESP 1 rate plan included reinstating the non-bypassable RSC Rider, which provided annual revenue of approximately $79 million. The OCC has appealed to the Ohio Supreme Court the PUCO’s decision approving the reversion to ESP 1 as well as argued for a refund of the RSC revenue dating back to August 2021. Oral arguments regarding this appeal were held on April 22, 2025, and a court decision is pending.
AES Ohio Smart Grid Comprehensive Settlement — On October 23, 2020, AES Ohio entered into a Stipulation and Recommendation with the staff of the PUCO, various customers and organizations representing customers of AES Ohio and certain other parties with respect to, among other matters, AES Ohio's applications for (i) approval of AES Ohio's plan to modernize its distribution grid (Smart Grid Phase 1), (ii) findings that AES Ohio passed the SEET for 2018 and 2019, and (iii) findings that AES Ohio's ESP 1 satisfies the SEET and the more favorable in the aggregate (MFA) regulatory test. On June 16, 2021, the PUCO issued their opinion and order accepting the stipulation as filed. The OCC appealed the final PUCO order with respect to the 2018 and 2019 SEET to the Ohio Supreme Court on December 6, 2021. Oral arguments regarding this appeal were held on April 2, 2025. The Ohio Supreme Court reversed the PUCO's opinion and order with respect to the methodology used by the PUCO to support its findings related to the 2018 and 2019 SEET, and remanded the case to the PUCO to conduct further analysis of the SEET for those years. In the proceeding on remand, AES Ohio filed testimony proposing a refund of $1.6 million based on methodologies sponsored by its external financial consultant. The PUCO held an evidentiary hearing on this issue on October 28 and 29, 2025, and a PUCO decision is pending.
AES Indiana Rate Case Filing — On June 3, 2025, AES Indiana filed a petition with the IURC for authority to increase its basic rates and charges. On October 15, 2025, AES Indiana entered into a Stipulation and Settlement Agreement (the “Settlement Agreement”) with most parties in AES Indiana’s pending regulatory rate review at the IURC. This Settlement Agreement provides for updated base rates for electric services in AES Indiana’s territory and is subject, and conditioned upon, approval by the IURC. Among other things, the Settlement Agreement proposes an increase in AES Indiana’s revenue of $90.7 million and provides a return on common equity of 9.75% and cost of long-term debt of 5.34%, on a rate base of approximately $5.5 billion for AES Indiana’s 2027 electric service base rates. The partial Settlement Agreement also includes a commitment to not implement additional base rate increases, following the implementation of new base rates under the settlement, until at least January 2030 and to not start a second TDSIC Plan before January 2028. An evidentiary hearing with the IURC was held on January 28 and 29, 2026, and AES Indiana anticipates a final order from the IURC in the second quarter of 2026.
AES 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 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
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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 December 31, 2025, the carrying value of our long-lived assets at Maritza is $64 million.
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 7A.— Quantitative and Qualitative Disclosures About Market Risk .
Capital Resources and Liquidity
Overview
As of December 31, 2025, the Company had unrestricted cash and cash equivalents of $1.4 billion, of which $10 million was held at the Parent Company and qualified holding companies. The Company had restricted cash and debt service reserves of $780 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $23.2 billion and $6 billion, respectively. Of the $2.2 billion of our current non-recourse debt, $2.2 billion was presented as such because it is due in the next twelve months and $20 million relates to debt considered in default. This default is not a payment default but is instead a technical default triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents. See Note 12— O bligations in Item 8.— Financial Statements of this Form 10-K for additional detail. As of December 31, 2025, the Company also had $616 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 $879 million in recourse debt which matures within the next twelve months, including $79 million in outstanding borrowings under the commercial paper program. Furthermore, we have $391 million due under supplier financing arrangements that have a guarantee, $204 million guaranteed by the Parent Company and $187 million guaranteed by subsidiaries. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions, or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other 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
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rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company does not have any material unhedged exposure to variable interest rate debt. Additionally, commercial paper issuances are short term in nature and subject the Parent Company to interest rate risk at the time of refinancing the paper. On a consolidated basis, of the Company's $29.5 billion of total gross debt outstanding as of December 31, 2025, approximately $7.3 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 December 31, 2025, the total maximum outstanding amount of hedges protecting the company against current and expected variable rate exposure was $9.1 billion. These hedges generally provide economic protection through the entire expected life of the projects, regardless of the type of debt issued to finance construction or refinance the projects in the future.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction, or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock, and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial and performance-related guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment, or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business' obligations up to the amount provided for in the relevant guarantee or other credit support. As of December 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 $3.8 billion in aggregate. This amount excludes arrangements that relate solely to the Company's own future performance, as well as those that are collateralized by letters of credit and other obligations discussed below.
Some counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. As of December 31, 2025, we had $220 million in letters of credit under bilateral agreements, $117 million in letters of credit outstanding provided under our unsecured credit facilities, and $50 million in letters of credit outstanding provided under our revolving credit facilities. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations.
Additionally, in connection with certain project financings, some of the Company's subsidiaries have expressly undertaken limited obligations and commitments. These contingent contractual obligations are issued at the subsidiary level and are non-recourse to the Parent Company. As of December 31, 2025, the consolidated maximum undiscounted potential exposure to guarantees, letters of credit, and surety bonds issued by our subsidiaries was $4.7 billion, including $2.5 billion of guarantees and commitments, $2.1 billion of letters of credit outstanding, and $74 million of surety bonds.
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
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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 December 31, 2025, the Company had approximately $119 million of gross accounts receivable classified as Other noncurrent assets . These noncurrent receivables mostly consist of accounts receivable in the U.S. and Chile that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond December 31, 2026, or one year from the latest balance sheet date. Noncurrent receivables in the U.S. pertain to the sale of the Redondo Beach land. Noncurrent receivables in Chile pertain primarily to payment deferrals granted to mining customers as part of our green blend agreements. See Note 7— Financing Receivables included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
As of December 31, 2025, the Company had an $862 million loan 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. Of the loan receivable balance, $107 million was classified in Other current assets and $755 million was classified in Loan receivable on the Consolidated Balance Sheets. See Note 7— Financing Receivables and Note 21— Revenue included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Cash Sources and Uses
The primary sources of cash for the Company in the year ended December 31, 2025 were debt financings, cash flows from operating activities, sales to noncontrolling interests, and purchases under supplier financing arrangements. The primary uses of cash in the year ended December 31, 2025 were repayments of debt, capital expenditures, repayments of obligations under supplier financing arrangements, and distributions to noncontrolling interests.
The primary sources of cash for the Company in the year ended December 31, 2024 were debt financings, cash flows from operating activities, purchases under supplier financing arrangements, sales to noncontrolling interests, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2024 were repayments of debt, capital expenditures, repayments of obligations under supplier financing arrangements, and purchases of short-term investments.
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A summary of cash-based activities is as follows (in millions):
Year Ended December 31,
Cash Sources:
Issuance of non-recourse debt
Net cash provided by operating activities
Borrowings under the revolving credit facilities
Sales to noncontrolling interests
Purchases under supplier financing arrangements
Issuance of preferred shares in subsidiaries
Issuance of recourse debt
Contributions from noncontrolling interests
Proceeds from the sale of business interests, net of cash and restricted cash sold
Sale of short-term investments
Other
Total Cash Sources
Cash Uses:
Capital expenditures (1)
Repayments under the revolving credit facilities
Repayments of non-recourse debt
Repayments of obligations under supplier financing arrangements
Distributions to noncontrolling interests
Repayments of recourse debt
Dividends paid on AES common stock
Purchase of emissions allowances
Purchase of short-term investments
Payments for financing fees
Acquisitions of business interests, net of cash and restricted cash acquired
Other (2)
Total Cash Uses
Net increase in Cash, Cash Equivalents, and Restricted Cash
(1) Includes interest capitalized on development and construction of $502 million and $637 million for the years ended December 31, 2025 and 2024, respectively. Of the total capitalized in 2025 and 2024, $483 million and $577 million, respectively, are related to recourse and non-recourse debt interest payments. The remaining capitalized interest is primarily related to supplier financing arrangements.
(2) Includes the $27 million and $63 million effect of exchange rate changes on cash, cash equivalents and restricted cash for the years ended December 31, 2025 and 2024, respectively.
Consolidated Cash Flows
The following table reflects the changes in operating, investing, and financing cash flows for the comparative twelve-month periods (in millions):
December 31,
Cash flows provided by (used in):
$ Change
Operating activities
Investing activities
Financing activities
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Operating Activities
Fiscal Year 2025 versus 2024
Net cash provided by operating activities increased $1.6 billion for the year ended December 31, 2025, compared to December 31, 2024.
Operating Cash Flows
(in millions)
(1) The change in adjusted net income is defined as the variance in net income , net of the total adjustments to net income as shown on the Consolidated Statements of Cash Flows in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
(2) The change in working capital is defined as the variance in total c hanges in operating assets and liabilities as shown on the Consolidated Statements of Cash Flows in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
• Adjusted net income increased $1.3 billion, primarily due to increased proceeds from the transfer of U.S. investment tax credits, and a decrease in cash paid for interest and income taxes, partially offset by lower margin at our Energy Infrastructure SBU.
• Change in working capital increased $291 million, primarily due to a decrease in accounts receivable due to the timing of collections and billings and an increase in contract liabilities related to development services in the U.S. These increases were partially offset by an increase in other current assets due to the timing of collection of tax credit transfer proceeds, the prior year sale of financing receivables under the Warrior Run PPA termination agreement, and an increase in inventory due to higher purchases and lower consumption.
Investing Activities
Fiscal Year 2025 versus 2024
Net cash used in investing activities decreased $1.5 billion for the year ended December 31, 2025 compared to December 31, 2024.
Investing Cash Flows
(in millions)
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• Cash paid for acquisitions of business interests decreased $138 million, primarily due to the prior year acquisition of Atacama Solar in Chile for $105 million, higher net acquisitions in the prior year of $64 million for various businesses at AES Clean Energy Development, and the prior year acquisition of Hoosier Wind for $49 million; partially offset by the current year acquisition of Crossvine for $78 million.
• Contributions to equity affiliates decreased $84 million, primarily driven by the prior year contributions to Gatun and sPower for $64 million and $22 million, respectively.
• Cash proceeds from sales of business interests decreased $315 million, primarily due to proceeds of $412 million, net of transaction costs and cash sold, from the sale of AES Brasil in the prior year; partially offset by the current year sell-down of Dominican Republic Renewables for $103 million.
• Capital expenditures decreased $1.5 billion, discussed further below.
Capital Expenditures
(in millions)
(1) Growth expenditures generally include expenditures related to development projects in construction, expenditures that increase capacity of a facility beyond the original design, and investments in general load growth or system modernization.
(2) Maintenance expenditures generally include expenditures that are necessary to maintain regular operations or net maximum capacity of a facility.
(3) Environmental expenditures generally include expenditures to comply with environmental laws and regulations, expenditures for safety programs and other expenditures to ensure a facility continues to operate in an environmentally responsible manner.
• Growth expenditures decreased $1.3 billion, primarily driven by a decrease in expenditures for U.S. and Dominican Republic renewables as well as transmission and distribution project investments at our U.S. utilities compared to the prior year; partially offset by an increase in expenditures for renewables projects in Chile in the current year.
• Maintenance expenditures decreased $186 million, primarily driven by a $69 million decrease due to timing of maintenance at Southland, AES Ohio, and TermoAndes, and a $61 million decrease due to the sale of AES Brasil in October 2024.
• Environmental expenditures decreased $3 million, with no material drivers.
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Financing Activities
Fiscal Year 2025 versus 2024
Net cash provided by financing activities decreased $3 billion for the year ended December 31, 2025 compared to December 31, 2024.
Financing Cash Flows
(in millions)
See Notes 12— O bligations , 17— Redeemable stock of subsidiaries, and 18— Equity in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant transactions.
• The $2.4 billion impact from non-course revolvers is primarily due to $1.4 billion of net repayments in the current year and $751 million net borrowings in the prior year at the Renewables SBU, and $247 million of net repayments in the current year and $69 million of net borrowings in the prior year at the Utilities SBU; partially offset by $122 million of higher net repayments at the Energy Infrastructure SBU in the prior year.
• The $1.3 billion impact from recourse debt is primarily due to the issuance of $1.5 billion subordinated notes at the Parent Company in the prior year and repayments of $898 million at the Parent Company in the current year, partially offset by current year issuance of $800 million of senior notes and repayments of $200 million in the prior year.
• The $881 million impact from non-recourse debt transactions is primarily due to $963 million lower net borrowings at the Utilities SBU and $451 increase in net repayments at the Energy Infrastructure SBU, partially offset by a $533 increase in net borrowings at the Renewables SBU.
• The $482 million impact from distributions to noncontrolling interests is primarily related to increases of $307 million and $191 million at AES Clean Energy and AES Indiana, respectively, mainly due to higher proceeds from the transfer of U.S. investment tax credits distributed to tax equity partners.
• The $300 million impact from the Parent Company revolver is due to higher net borrowings in the current year.
• The $992 million impact from issuance of preferred shares in subsidiaries is primarily due to the proceeds received from the issuance of preferred shares in AES Global Insurance, Bellefield 2 Equity Holdings, AES DevCo HoldCo, Desarrollos Renovables, and the Bolero BESS project.
• The $837 million impact from sales to noncontrolling interests is primarily due to $540 million from the sale of ownership interest in AES Ohio and increase in proceeds of $328 million and $207 million at AES Clean Energy Development and AES Indiana, respectively, due to higher sales of ownership in project companies to tax equity investors; partially offset by a $104 million decrease in sales under the Chile Renovables partnership with GIP, a decrease of $103 million in proceeds at AES Renewable Holdings due to higher sales of ownership in project companies to tax equity investors in the prior year, and $35 million related to the prior year sale of ownership interest in the Marahu project.
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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 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):
December 31, 2025
December 31, 2024
Consolidated cash and cash equivalents
Less: Cash and cash equivalents at subsidiaries
Parent Company and qualified holding companies' cash and cash equivalents
Commitments under the Parent Company credit facilities
Less: Letters of credit under the credit facilities
Less: Borrowings under the credit facility
Less: Borrowings under the commercial paper program
Borrowings available under the Parent Company credit facilities
Total Parent Company Liquidity
The Parent Company paid dividends of $0.70 per outstanding share to its common stockholders during the year ended December 31, 2025. 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 $6.0 billion and $5.7 billion as of December 31, 2025 and 2024, respectively. See Note 12— O bligations in Item 8.— Financial Statements and Supplementary Data of this 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 facilities 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 this Form 10-K.
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
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and other reporting requirements. As of December 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.
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 Consolidated Balance Sheets amounts to $2.2 billion. The portion of current debt related to such defaults was $20 million at December 31, 2025, all of which was non-recourse debt related to AES Ilumina. This default is not a payment default, but is instead a technical default triggered by failure to comply with other covenants or other conditions contained in the non-recourse debt documents. See Note 12— Obligations in Item 8.— Financial Statements and Supplementary Data of this Form 10-K 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 December 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 completed fiscal quarters. As of December 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.
Contractual Obligations and Contingent Contractual Obligations
A summary of our contractual obligations, commitments, and other liabilities as of December 31, 2025 is presented below (in millions):
Contractual Obligations
Total
Less than 1 year
1-3 years
3-5 years
More than 5 years
Other
Footnote Reference (5)
Debt obligations (1) (2)
Interest payments on long-term debt (3)
Supplier financing arrangements
Finance lease obligations (2)
Operating lease obligations (2)
Electricity obligations
Fuel obligations
Other purchase obligations
Other long-term liabilities reflected on AES' consolidated balance sheet under GAAP (2) (4)
Total
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(1) Includes recourse and non-recourse debt presented on the Consolidated Balance Sheets. These amounts exclude finance lease liabilities which are included in the finance lease obligations category.
(2) Excludes any businesses classified as held-for-sale. See Note 25— Held-for-Sale and Dispositions in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for additional information related to held-for-sale businesses.
(3) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.
(4) These amounts do not include current liabilities on the Consolidated Balance Sheets except for the current portion of uncertain tax obligations. Noncurrent uncertain tax obligations are reflected in the "Other" column of the table above as the Company is not able to reasonably estimate the timing of the future payments. In addition, these amounts do not include: (1) regulatory liabilities (See Note 11— Regulatory Assets and Liabilities ), (2) contingencies (See Note 14— Contingencies ), (3) pension and other postretirement employee benefit liabilities (see Note 16— Benefit Plans ), (4) derivatives and incentive compensation (See Note 6— Derivative Instruments and Hedging Activities ) or (5) any taxes (See Note 24— Income Taxes ) except for uncertain tax obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial Statements included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for additional information on the items excluded.
(5) For further information see the note referenced below in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
The following table presents our Parent Company's consolidated contingent contractual obligations as of December 31, 2025:
Parent Company Contingent Contractual Obligations
Maximum Exposure (in millions)
Number of Agreements
Maximum Exposure Range for Each Agreement (in millions)
Guarantees and commitments (1)
Letters of credit under bilateral agreements
Letters of credit under the unsecured credit facilities
Letters of credit under the revolving credit facilities
Total
(1) Excludes payment obligation and commercial transaction arrangements entered into by the Parent Company on behalf of its consolidated subsidiaries, which relate to the Company's own future performance. See Schedule I— Condensed Financial Information of Registrant for additional information on guarantees issued by the Parent Company.
Additionally, some of the Company's subsidiaries have contingent contractual obligations that are non-recourse to the Parent Company. The following table presents our subsidiaries' consolidated contingent contractual obligations as of December 31, 2025:
Subsidiary Contingent Contractual Obligations
Maximum Exposure (in millions)
Number of Agreements
Maximum Exposure Range for Each Agreement (in millions)
Guarantees and commitments
Letters of credit under subsidiary credit facilities
Surety bonds
Total
We have a diverse portfolio of performance-related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, sponsor support, and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations beyond 2025, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.
Critical Accounting Policies and Estimates
The 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. AES' significant accounting policies are described in Note 1— General and Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
An accounting estimate is considered critical if the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or the impact of the estimates and assumptions on financial condition or operating performance is material.
Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to
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these balances in future periods. Management has discussed these critical accounting policies with the Audit Committee, as appropriate. Listed below are the Company's most significant critical accounting estimates and assumptions used in the preparation of the Consolidated Financial Statements.
Income Taxes — We are subject to income taxes in both the U.S. and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. Certain of the Company's subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each tax jurisdiction when determining the adequacy of the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more likely than not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.
Because we have a wide range of statutory tax rates in the multiple jurisdictions in which we operate, any changes in our geographical earnings mix could materially impact our effective tax rate. Furthermore, our tax position could be adversely impacted by changes in tax laws, tax treaties or tax regulations, or the interpretation or enforcement thereof and such changes may be more likely or become more likely in view of recent economic trends in certain of the jurisdictions in which we operate.
In addition, no taxes have been recorded on undistributed earnings for certain of our non-U.S. subsidiaries to the extent such earnings are considered to be indefinitely reinvested in the operations of those subsidiaries. Should the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state income taxes.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.
In addition, the Company has elected an accounting policy not to consider the effects of being subject to the corporate alternative minimum tax in future periods when assessing the realizability of our deferred tax assets, carryforwards, and tax credits. Any effect on the realization of deferred tax assets will be recognized in the period they arise.
The Company accounts for tax credits that it will retain or transfer as a reduction in income tax expense by either including the expected amount of the tax credit to be claimed or the cash to be received when transferred, respectively, in the calculation of its annual effective tax rate. The estimated tax credits are updated on a quarterly basis, with the year-end calculation including only the tax credits that are associated with projects placed in service, comprising credits claimed or transferred during the year. In assessing realizability for credits to be transferred, the Company includes cash it anticipates receiving in establishing any valuation allowance and establishes a valuation allowance equal to its best estimate of any discount on the transfer. The receipt of cash from the transfer of tax credits is treated as an operating cash inflow.
Impairments — Our accounting policies on goodwill and long-lived assets, including events that lead to possible impairment, are described in detail in Note 1— General and Summary of Significant Accounting Policies , included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K. The Company makes considerable judgments in its impairment evaluations of goodwill and long-lived assets, starting with determining if an impairment indicator exists. The Company exercises judgment in determining if these indicators or events represent an impairment indicator requiring the computation of the fair value of goodwill and/or the recoverability of long-lived assets. The fair value determination is typically the most judgmental part in an impairment evaluation. Please see Fair Value below for further detail.
As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the surplus of fair value above carrying amount decreases or becomes negative. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations
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inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.
Further discussion of the impairment charges recognized by the Company can be found within Note 10— Goodwill and Other Intangible Assets and Note 23— Asset Impairment Expense to the Consolidated Financial Statements included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
Depreciation — Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or component basis. The Company considers many factors in its estimate of useful lives, including expected usage, physical deterioration, technological changes, existence and length of off-taker agreements, and laws and regulations, among others. In certain circumstances, these estimates involve significant judgment and require management to forecast the impact of relevant factors over an extended time horizon.
Useful life estimates are continually evaluated for appropriateness as changes in the relevant factors arise, including when a long-lived asset group is tested for recoverability. Depreciation studies are performed periodically for assets subject to composite depreciation. Any change to useful lives is considered a change in accounting estimate and is made on a prospective basis.
Fair Value — For information regarding the fair value hierarchy, see Note 1— General and Summary of Significant Accounting Policies included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
Fair Value of Financial Instruments — A significant number of the Company's financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company's investments are primarily certificates of deposit and mutual funds. Derivatives are valued using observable data as inputs into internal valuation models. The Company's derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 5— Fair Value included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
Fair Value of Nonfinancial Assets and Liabilities — Significant estimates are made in determining the fair value of long-lived tangible and intangible assets (i.e., property, plant, and equipment, intangible assets, and goodwill) during the impairment evaluation process. In addition, the relevant accounting guidance requires the Company to recognize the majority of assets acquired and liabilities assumed in a business combination and asset acquisitions by VIEs at fair value.
The Company may engage an independent valuation firm to assist management with the valuation. The Company generally utilizes the income approach to value nonfinancial assets and liabilities, specifically a Discounted Cash Flow ("DCF") model to estimate fair value by discounting cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of our cash flow forecasts. Examples of the input assumptions that our forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices, changes in interest rates, and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. It is not uncommon that different market data sources have different views of the macroeconomic factor expectations and related assumptions. As a result, macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations these ranges become wide and the use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg). The Company selects and uses a set of publicly traded companies from the relevant industry to estimate the discount rate inputs. Management applies judgment in the selection of such companies based on its view of the
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most likely market participants. It is reasonably possible that the selection of a different set of likely market participants could produce different input assumptions and result in the use of a different discount rate.
Accounting for Derivative Instruments and Hedging Activities — We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity, and foreign currency exposures. We do not enter into derivative transactions for trading purposes. See Note 6— Derivative Instruments and Hedging Activities included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information on the classification.
The fair value measurement standard requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Credit risk for AES is evaluated at the level of the entity that is party to the contract. Nonperformance risk on the Company's derivative instruments is an adjustment to the fair value position that is derived from internally developed valuation models that utilize market inputs that may or may not be observable.
As a result of uncertainty, complexity, and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings, and future foreign exchange rates. Refer to Note 5— Fair Value included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for additional details.
The fair value of our derivative portfolio is generally determined using internal and third-party valuation models, most of which are based on observable market inputs, including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg, Reuters, and Platt's). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument's fair value. In certain instances, published pricing may not extend through the remaining term of the contract, and management must make assumptions to extrapolate the curve. Specifically, where there is limited forward curve data with respect to foreign exchange contracts beyond the traded points, the Company utilizes the interest rate differential approach to construct the remaining portion of the forward curve. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.
Regulatory Assets — Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities, and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.
Consolidation — The Company enters into transactions impacting the Company's equity interests in its affiliates. In connection with each transaction, the Company must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, the Company is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights.
If the entity is determined to be a variable interest entity, the most significant judgment in determining whether the Company must consolidate the entity is whether the Company, including its related parties and de facto agents, collectively have power and benefits. If AES is determined to have power and benefits, the entity will be consolidated by AES.
Alternatively, if the entity is determined to be a voting model entity, the most significant judgments involve determining whether the non-AES shareholders have substantive participating rights. The assessment of shareholder rights and whether they are substantive participating rights requires significant judgment since the rights provided under shareholders' agreements may include selecting, terminating, and setting the compensation of management responsible for implementing the subsidiary's policies and procedures, and establishing operating and capital decisions of the entity, including budgets, in the ordinary course of business. On the other hand, if shareholder rights are only protective in nature (referred to as protective rights), then such rights would not
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overcome the presumption that the owner of a majority voting interest shall consolidate its investee. Significant judgment is required to determine whether minority rights represent substantive participating rights or protective rights that do not affect the evaluation of control. While both represent an approval or veto right, a distinguishing factor is the underlying activity or action to which the right relates.
Hypothetical Liquidation at Book Value — Certain of the Company's businesses are subject to profit-sharing arrangements where the allocation of earnings and losses, cash distributions, and tax benefits are not based on fixed ownership percentages.
Many of these arrangements exist for certain U.S. renewable generation partnerships to designate different allocations of value among investors, where the allocations change in form or percentage over the life of the partnership. For these businesses, the Company uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership were to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions.
The HLBV method is used both to allocate the equity earnings attributable to AES when the Company accounts for the renewables business as an equity method investment and to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.
Pension and Other Postretirement Plans — The Company recognizes a net asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in actuarial gains or losses recognized in AOCL, except for those plans at certain of the Company's regulated utilities that can recover portions of their pension and postretirement obligations through future rates. The valuation of the Company's benefit obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the most significant of which include the discount rate and expected return on plan assets. These assumptions are reviewed by the Company on an annual basis. Refer to Note 1— General and Summary of Significant Accounting Policies included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information.
Revenue Recognition — The Company recognizes revenue to depict the transfer of energy, capacity, and other services to customers in an amount that reflects the consideration to which we expect to be entitled. In applying the revenue model, we determine whether the sale of energy, capacity, and other services represent a single performance obligation based on the individual market and terms of the contract. Generally, the promise to transfer energy and capacity represent a performance obligation that is satisfied over time and meets the criteria to be accounted for as a series of distinct goods or services. Progress toward satisfaction of a performance obligation is measured using output methods, such as MWhs delivered or MWs made available, and when we are entitled to consideration in an amount that corresponds directly to the value of our performance completed to date, we recognize revenue in the amount to which we have the right to invoice. For further information regarding the nature of our revenue streams and our critical accounting policies affecting revenue recognition, see Note 1— General and Summary of Significant Accounting Policies included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
Leases — The Company recognizes operating and finance right-of-use assets and lease liabilities on the Consolidated Balance Sheets for most leases with an initial term of greater than 12 months. Lease liabilities and their corresponding right-of-use assets are recorded based on the present value of lease payments over the expected lease term. Our subsidiaries’ incremental borrowing rates are used in determining the present value of lease payments when the implicit rate is not readily determinable. Certain adjustments to the right-of-use asset may be required for items such as prepayments, lease incentives, or initial direct costs. For further information regarding the nature of our leases and our critical accounting policies affecting leases, see Note 1— General and Summary of Significant Accounting Policies included in Item 8.— Financial Statements and Supplementary Data of this Form 10-
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Credit Losses — The Company uses a forward-looking "expected loss" model to recognize allowances for credit losses on trade and other receivables, held-to-maturity debt securities, loans, and other instruments. For available-for-sale debt securities with unrealized losses, the Company continues to measure impairments of available-for-sale securities as was done under previous GAAP, except that unrealized losses due to credit-related factors are now recognized as an allowance on the Consolidated Balance Sheet with a corresponding adjustment to earnings in the Consolidated Statements of Operations. For further information regarding credit losses, see Note 1— General and Summary of Significant Accounting Policies and Note 8— Allowance for Credit Losses included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K.
New Accounting Pronouncements
See Note 1— General and Summary of Significant Accounting Policies included in Item 8.— Financial Statements and Supplementary Data of this Form 10-K for further information about new accounting pronouncements adopted during 2025 and accounting pronouncements issued, but not yet effective.
