AES CORP (AES)

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For discussion of the Company's year ended December 31, 2023 compared to the year ended December 31, 2022, refer to Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2023 Form 10-K filed with the SEC on February 26, 2024.

Executive Summary

In 2024, AES delivered on its strategic and financial objectives. We completed construction or the acquisition of 3.0 GW of renewables and energy storage, construction of a 670 MW combined cycle gas plant, and signed long-term PPAs for an additional 4.4 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 increased $984 million, from a net loss of $182 million in 2023 to net income of $802 million in 2024. This increase is the result of lower impairments, unrealized foreign currency gains in the current year versus losses in the prior year, gain on sale of AES Brasil, favorable contributions at the Utilities and New Energy Technologies SBUs, and higher contributions from renewables projects placed in service in the current year; partially offset by higher interest expense and lower interest income, and the prior year gain on sell-down of Fluence.

Adjusted EBITDA, a non-GAAP measure, decreased $189 million, from $2,828 million to $2,639 million, mainly driven by record-breaking drought conditions and outages in Colombia at the Renewables SBU, lower margins at the Energy Infrastructure SBU due to prior year margin at the hedged merchant Southland facilities that are contracted primarily for capacity in the current year and higher outages; partially offset by higher contributions at the Utilities SBU and higher revenues from new projects at the Renewables SBU.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $513 million, from $3,439 million to $3,952 million, primarily due to higher realized tax attributes driven by more renewables projects placed in service, partially offset by the drivers above.

Compared with last year, diluted earnings per share from continuing operations increased $2.03, from $0.34 to $2.37. This increase is mainly driven by lower long-lived asset impairments in the current year, higher contributions from renewables projects placed in service in the current year, prior year unrealized foreign currency losses at the Energy Infrastructure SBU, the gain on sale of AES Brasil, and lower income tax expense. This was partially offset by higher interest expense and lower interest income, and lower margins due to outages.

Adjusted EPS, a non-GAAP measure, increased $0.38 from $1.76 to $2.14, mainly driven by higher contributions from renewables projects placed in service in the current year, a lower adjusted tax rate, and higher contributions from the Utilities SBU; partially offset by lower contributions from the Energy Infrastructure SBU.

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Review of Consolidated Results of Operations

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, operations and maintenance costs, depreciation and amortization expenses, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (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.

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Consolidated Revenue and Operating Margin

Year Ended December 31, 2024

Revenue

(in millions)

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

•$598 million at Energy Infrastructure primarily driven by a $398 million decrease in regulated contract sales and prices, $319 million due to higher revenues from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, $73 million due to lower generation driven by lower dispatch in Argentina, and $69 million impact from the selldown of Amman East and IPP4 in Jordan; partially offset by $195 million higher realized gains on power swaps; and

•$75 million at New Energy Technologies mainly driven by the sale of the Fallbrook project in March 2023.

These unfavorable impacts were partially offset by increases of:

•$171 million at Renewables mainly driven by $205 million due to new projects in service, $61 million of unrealized derivative gains, $58 million of higher contracted energy sales, and $35 million due to the appreciation of the Colombian peso; partially offset by $125 million impact from the sale of our controlling interest in AES Brasil, and $69 million due to higher outages and record-breaking drought conditions in Colombia; and

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

Operating Margin

(in millions)

Consolidated Operating Margin — Operating margin decreased $190 million, or 8%, in 2024 compared to 2023, driven by:

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•$145 million at Energy Infrastructure mainly driven by $110 million due to higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, $54 million impact from the selldown of Amman East and IPP4 in Jordan, $51 million due to higher outages, $39 million due to end of commercial operations at Warrior Run in May 2024, and $31 million due to lower LNG transactions; partially offset by $82 million from a PPA termination loss recognized in the prior year and $45 million of unrealized derivative gains;

•$133 million at Renewables driven by $148 million impact primarily from record-breaking drought conditions in Colombia, alongside drier hydrological conditions in Brazil, $45 million impact of outages at Colombia due to a flooding incident at the Chivor plant which occurred in June 2024, $44 million impact from the sale of our controlling interest in AES Brasil, and $29 million higher fixed costs primarily due to an accelerated growth plan; partially offset by unrealized derivative gains of $61 million and higher contracted energy sales of $58 million; and

•$24 million at Corporate and Other primarily driven by higher eliminations of insurance recoveries booked at the businesses related to AES' self-insurance company.

These unfavorable impacts were partially offset by an increase of $110 million at Utilities primarily driven by $83 million due to higher transmission and rider revenues, $76 million due to higher retail rates as a result of the 2024 Base Rate Order, and $72 million due to higher demand primarily from the impact of weather; partially offset by $57 million higher depreciation from additional assets placed in service, the prior year $29 million deferral of power purchase costs associated with the approval of ESP 4, and $25 million higher expected credit losses due to the one-time implementation of customer billing system upgrades.

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 increased $33 million, or 13%, to $288 million in 2024 compared to $255 million in 2023, primarily due to increased business development costs, higher people costs, higher professional fees, and higher IT costs.

Interest expense

Interest expense increased $166 million, or 13%, to $1,485 million in 2024, compared to $1,319 million in 2023. This increase was driven by higher interest expense of $67 million and $52 million at the Renewables and Utilities SBUs, respectively, primarily due to new debt issued, net of increased capitalized interest, and higher interest at Corporate of $63 million primarily due to a higher weighted average interest rate and debt balance at the Parent Company; partially offset by a $16 million decrease at the Energy Infrastructure SBU primarily due to lower debt balances.

Interest income

Interest income decreased $170 million, or 31%, to $381 million in 2024, compared to $551 million in 2023 primarily due to a decrease in Argentina of $138 million primarily due to lower short-term investments at lower rates and a decrease in Brazil of $51 million due to lower short-term investments and the sale of AES Brasil in October 2024; partially offset by an increase in Chile of $30 million mainly driven by interest recognized on the Stabilization Fund receivables.

Loss on extinguishment of debt

Loss on extinguishment of debt decreased $46 million to $17 million in 2024, compared to $63 million in 2023. This decrease was primarily due to prior year losses of $47 million and $10 million due to prepayments at AES Andes and AES Hispanola Holdings BV, respectively, partially offset by a current year loss of $10 million due to a prepayment at AES Andes.

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See Note 12—Obligations included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Other income

Other income increased $67 million, or 75%, to $156 million in 2024, compared to $89 million in 2023 primarily due to the bargain purchase gain recognized on the Madison and Birdseye acquisition for $20 million, a $17 million increase in gains on remeasurement of contingent consideration primarily on projects acquired at AES Clean Energy, a $14 million gain corresponding to the step acquisition of Felix, and an indexation adjustment of Stabilization Fund receivables at AES Andes of $12 million.

Other expense

Other expense increased $76 million, or 77%, to $175 million in 2024, compared to $99 million in 2023 primarily driven by $52 million higher losses on commencement of sales-type leases at AES Renewable Holdings, a $43 million increase in losses on remeasurement of contingent consideration primarily on projects acquired at AES Clean Energy, and a $20 million loss related to legal expenses and other direct costs associated with the troubled debt restructuring at Puerto Rico. This was partially offset by a $36 million decrease in loss on sale and disposal of assets, mainly driven by prior year impairments of inventory due to the planned early plant closures at Ventanas 2, Norgener, and Warrior Run.

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 (loss) on disposal and sale of business interests

Gain on disposal and sale of business increased $217 million to $351 million in 2024, compared to $134 million in 2023. This increase was driven by the gain on sale of AES Brasil of $312 million and a $52 million gain corresponding to the dilution of AES' ownership in Uplight as a result of the AutoGrid acquisition; partially offset by a $136 million gain on sale of shares of Fluence, our equity method investment, in 2023, and the $10 million loss on the selldown of Amman East and IPP4 in Jordan, 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.

Goodwill impairment expense

Goodwill impairment expense was $12 million in 2023 due to impairment at the TEG TEP reporting unit primarily driven by an increase in the discount rate due to increasing risk of non-renewal of operating permits required after March 31, 2024.

See Note 10—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Asset impairment expense

Asset impairment expense decreased $693 million, or 65%, to $374 million in 2024, compared to $1.1 billion in 2023. This decrease was primarily due to higher prior year impairments, including a $198 million impairment associated with PJM's approval to retire the Warrior Run coal-fired facility; a $186 million impairment at New York Wind related to a repowering project that will result in decommissioning the existing turbines and reducing their depreciable lives; a $137 million impairment associated with the commitment to accelerate the retirement of the Norgener coal-fired facility in Chile; a $77 million and $59 million impairment at TEG and TEP, respectively, due to a reduction in expected capacity cash flows after expiration of the current PPA; and a $59 million impairment at Amman East and IPP4 in Jordan due to the delay in closing the sale transaction. In addition, the decrease was driven by lower impairment expense of $105 million associated with the held-for-sale classification of Mong Duong and lower impairment expense of $56 million at AES Clean Energy Development related to the write-off of project development intangibles for projects that were determined to be no longer viable. This was partially offset by current year impairments of $125 million and $80 million at Ventanas and AES Brasil, respectively, after meeting held-for-sale criteria.

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:

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(1)    Includes peso-denominated energy receivable indexed to the USD through the FONINVEMEM agreement which is considered a foreign currency derivative. See Note 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

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

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.

The Company recognized net foreign currency transaction losses of $359 million in 2023, primarily driven by the depreciation of the Argentine peso, unrealized losses related to an intercompany loan denominated in the Colombian peso, and realized and unrealized foreign currency derivative losses in South America due to the depreciating Colombian peso.

Income tax expense

Income tax expense was $59 million in 2024 compared to $261 million in 2023. The Company's effective tax rates were 7% and 251% for the years ended December 31, 2024 and 2023, respectively.

The 2024 effective tax rate was impacted by the current 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.

The 2023 effective tax rate was impacted by the allocation of losses to noncontrolling interest in U.S. tax-equity partnerships and pretax impairments at certain Mexican subsidiaries and at the Mong Duong coal-fired plant in Vietnam. These impacts were partially offset by inflationary and foreign currency impacts at certain Argentine businesses, net of valuation allowances, as well as the recognition of U.S. investment tax credits for renewables projects placed in service in 2023. See Note 23—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for details of the asset impairments.

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 decreased $6 million, or 19%, to $26 million in 2024, compared to $32 million in 2023. This decrease was primarily driven by a $30 million decrease in losses from Fluence, mainly attributable to improved margins on a new product line. This was partially offset by a $13 million decrease in earnings from Mesa La Paz, primarily due to the prior year termination of derivative positions due to a contract amendment; lower earnings from sPower of $7 million, mainly due to lower earnings from renewables projects that came online; and lower earnings from Energía Natural Dominicana Enadom of $7 million due to lower capitalized interest and higher depreciation.

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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Net income (loss) attributable to noncontrolling interests and redeemable stock of subsidiaries

Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries increased $446 million to $877 million in 2024, compared to $431 million in 2023. This increase was primarily due to:

•Higher allocation of losses to tax equity investors on renewables projects placed in service of $496 million; and

•Higher losses at Brazil of $60 million, primarily due to held-for-sale impairment.

These drivers were partially offset by:

•Higher held-for-sale impairment at Mong Duong in the prior year than the current year of $48 million; and

•Selldowns of business interests resulting in larger shares of income attributable to minority shareholders at the Energy Infrastructure SBU of $46 million.

Net income (loss) attributable to The AES Corporation

Net income attributable to The AES Corporation increased $1,430 million to $1,679 million in 2024, compared to $249 million in 2023. This increase was primarily due to:

•Lower long-lived asset impairments in the current year of $589 million;

•Higher contributions from renewables projects placed in service in the current year of $496 million;

•Unrealized foreign currency losses in the prior year exceeding current year gains by $345 million, primarily driven by higher losses in the prior year at the Energy Infrastructure SBU;

•Gain on sale of AES Brasil in the current year of $312 million;

•Lower income tax expense attributable to AES, primarily driven by $273 million of tax benefit resulting from the transfer of ITCs directly to third parties; and

•Higher margin from the Utilities SBU impacting net income attributable to AES by $77 million, mainly driven by higher transmission and rider revenues and higher retail rates.

These drivers were partially offset by:

•Higher interest expense and lower interest income in the current year of $245 million;

•Lower margin from the Energy Infrastructure SBU impacting net income attributable to AES by $147 million, mainly driven by selldowns, higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, and higher outages;

•Lower margin at the Renewables SBU impacting net income attributable to AES by $145 million, mainly driven by record-breaking drought conditions and partial outage due to a flooding incident in Colombia; and

•Gain on sale of shares in Fluence in the prior year of $136 million.

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 our businesses in Chile); and New Energy Technologies (investments in Fluence, Uplight, Maximo, and other new and innovative energy technology businesses). Our businesses in Chile, which have a mix of generation sources, including renewables, are included within the Energy Infrastructure SBU, as the generation from all sources is pooled to service our existing PPAs.

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.

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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 and $16 million in each of the years ended December 31, 2024 and 2023, respectively.

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 2023 or 2024.

For the year ended December 31, 2023, the Company changed the definition of Adjusted EPS to remove the adjustment for tax benefit or expense related to the enactment effects of 2017 U.S. tax law reform and related regulations and any subsequent period adjustments related to enactment effects, including the 2021 tax benefit on reversal of uncertain tax positions effectively settled upon the closure of the Company's U.S. tax return exam. As this adjustment was specific to the impacts of tax law reform enacted in 2017, we believe removing this adjustment from our non-GAAP definition provides simplification and clarity for our investors. There were no such impacts in 2022 or 2023.

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; and (e) gains, losses, and costs due to the early retirement of debt or troubled debt restructuring.

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 or retire debt, 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

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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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(1)The allocation of earnings and losses to tax equity investors from both consolidated entities and equity affiliates is removed from Adjusted EBITDA. NCI also excludes amounts allocated to preferred shareholders during the construction phase before a project becomes operational, as this is akin to a financing arrangement.

(2)         Adjusted EBITDA with Tax Attributes includes the impact of the share of the ITCs, PTCs, and depreciation deductions allocated to tax equity investors under the HLBV accounting method and recognized as Net loss (income) attributable to noncontrolling interests and redeemable stock of subsidiaries on the 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; and (e) gains, losses and costs due to the early retirement of debt or troubled debt restructuring. 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 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, and strategic decisions to dispose of or acquire business interests or retire debt, 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.

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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, 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; and (e) gains, losses and costs due to the early retirement of debt or troubled debt restructuring.

The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company's internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses pertaining to derivative transactions, equity securities, or financial assets and liabilities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, and strategic decisions to dispose of or acquire business interests or retire debt, 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.

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(1)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.

(2)Amount primarily relates to unrealized derivative losses due to the termination of a PPA of $72 million, or $0.10 per share and net unrealized derivative losses at AES Clean Energy of $20 million, or $0.03 per share, offset by net unrealized derivative gains at the Energy Infrastructure SBU of $46 million, or $0.06 per share.

(3)Amount primarily relates to unrealized foreign currency losses in Argentina of $262 million, or $0.37 per share, mainly associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized foreign currency losses at AES Andes of $25 million, or $0.03 per share.

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(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 the gain on sale of Fluence shares of $136 million, or $0.19 per share, partially offset by costs due to early plant closure at the Ventanas 2 and Norgener coal-fired plants in Chile of $37 million, or $0.05 per share and at Warrior Run of $6 million, or $0.01 per share, and day-one losses recognized at commencement of sales-type leases at AES Renewable Holdings of $20 million, or $0.03 per share.

(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 asset impairments at Warrior Run of $198 million, or $0.28 per share, at New York Wind of $139 million, or $0.20 per share, at the Norgener coal-fired plant in Chile of $136 million, or $0.19 per share, at TEG and TEP of $76 million and $58 million, respectively, or $0.19 per share, AES Clean Energy development projects of $114 million, or $0.16 per share, at Mong Duong of $88 million, or $0.12 per share, at Jordan of $21 million, or $0.03 per share, and at the GAF Projects at AES Renewable Holdings of $18 million, or $0.03 per share, and a goodwill impairment at the TEG TEP reporting unit of $12 million, or $0.02 per share.

(8)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.

(9)Amount primarily relates to losses incurred at AES Andes due to early retirement of debt of $46 million, or $0.07 per share, and loss on early retirement of debt at AES Hispanola Holdings BV of $10 million, or $0.01 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 sales-type lease loss at AES Renewable Holdings of $13 million, or $0.02 per share.

(11)Amount primarily relates to income tax benefits associated with the asset impairments at Warrior Run of $46 million, or $0.06 per share, at the Norgener coal-fired plant in Chile of $37 million, or $0.05 per share, at New York Wind of $32 million, or $0.05 per share, at TEG and TEP of $27 million, or $0.04 per share, and at AES Clean Energy development projects of $26 million, or $0.04 per share; income tax benefits associated with the recognition of unrealized losses due to the termination of a PPA of $17 million, or $0.02 per share; and income tax benefits associated with losses incurred at AES Andes due to early retirement of debt of $13 million, or $0.02 per share; partially offset by income tax expense associated with the gain on sale of Fluence shares of $31 million, or $0.04 per share.

Renewables SBU

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

_____________________________

(1)    A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

Operating Margin decreased $133 million driven by a $148 million impact primarily from record-breaking drought conditions in Colombia, alongside drier hydrological conditions in Brazil, a $45 million impact from outages at Colombia due to a flooding incident at the Chivor plant which occurred in June 2024, a $44 million impact from the sale of our controlling interest in AES Brasil, and a $29 million impact from higher fixed costs primarily due to an accelerated growth plan. These negative impacts were partially offset by a $33 million positive impact from new businesses, unrealized derivative gains of $61 million, and a $58 million impact from higher contracted energy sales.

Adjusted EBITDA decreased $100 million primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, and depreciation expense.

Adjusted EBITDA with Tax Attributes increased $600 million, primarily due to higher realized tax attributes driven by more projects being placed in service, partially offset by the decrease in Adjusted EBITDA. For the year ended December 31, 2024 and 2023, we realized $1,293 million and $593 million, respectively, from tax attributes earned by AES Clean Energy businesses.

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Utilities SBU

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

_____________________________

(1)    A non-GAAP financial measure. See SBU 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 $110 million mainly driven by $83 million due to higher transmission and rider revenues, $76 million due to higher retail rates as a result of the 2024 Base Rate Order, and $72 million due to higher demand primarily from the impact of weather. These increases are partially offset by $57 million due to higher depreciation expense from additional assets placed in service, higher amortization of regulatory assets and changes in depreciation rates as a result of the 2024 Base Rate Order, $29 million due to the prior year one-time deferral of purchased power costs associated with the approval of ESP 4, and $25 million higher expected credit losses due to the temporary pause of customer disconnections related to the implementation of customer billing system upgrades.

Adjusted EBITDA increased $114 million primarily due to the drivers above, adjusted for NCI and depreciation expense.

Adjusted EBITDA with Tax Attributes increased $116 million mainly due to the drivers above.

Adjusted PTC increased $29 million primarily due to the operating margin drivers above, partially offset by higher interest expense due to increased borrowings and the prior year one-time deferral of carrying costs associated with the approval of ESP 4, and NCI adjustments.

Energy Infrastructure SBU

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

_____________________________

(1)    A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

Operating Margin decreased $145 million, mainly driven by $110 million due to higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, $54 million due to the impact of the selldown of Amman East and IPP4 in Jordan, $51 million due to higher outages, $39 million due to end of commercial operations at Warrior Run in May 2024, and $31 million from lower LNG transactions.

The decrease in Operating Margin is partially offset by $82 million from a PPA termination loss recognized in the prior year and $45 million of unrealized gains resulting from derivatives.

Adjusted EBITDA decreased $174 million, primarily due to the drivers above, adjusted for NCI and unrealized derivatives, and lower realized foreign currency losses.

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New Energy Technologies SBU

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

_____________________________

(1)    A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

Operating Margin increased $2 million, with no material drivers.

Adjusted EBITDA increased $24 million, primarily driven by a $44 million improvement in the share of results at Fluence mainly due to improved margins, partially offset by the prior year settlement of contractual claims with a battery module vendor. This increase was partially offset by $21 million higher general and administrative expenses mainly related to higher development costs.

Key Trends and Uncertainties

During 2025 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.—Business and Item 1A.—Risk Factors of this Form 10-K.

Operational

Trade Restrictions and Supply Chain — In recent years, the U.S. Department of Commerce (“Commerce”) has initiated investigations into whether imports into the U.S. of solar cells and panels from Cambodia, Malaysia, Thailand, and Vietnam (“Southeast Asia”) are circumventing antidumping and countervailing duty (“AD/CVD”) orders on solar cells and panels from China. One such investigation initiated in April of 2022 resulted in a final determination by Commerce that circumvention would be deemed to occur under certain circumstances, resulting in the imposition AD and CVD duties on the imported cells and panels. Such determination and related matters remain the subject of ongoing litigation. Separate AD/CVD investigations initiated by Commerce in May 2024 resulted in preliminary determinations by Commerce that Southeast Asia countries were also dumping and receiving subsidies and therefore Commerce established CVD and AD rates on solar manufacturers. The U.S. International Trade Commission (the “ITC”) is also investigating this matter. If the Commerce and ITC investigations result in Commerce issuing AD/CVD orders, the orders are likely to be imposed in June 2025.

Separately, the United States maintains a global tariff (currently 14.25% ad valorem) on solar cells and modules pursuant to the Section 201 Safeguard Action on crystalline silicon photovoltaic products, which became effective in February 2018. On June 21, 2024, President Biden issued Proclamation 10779, revoking the exclusion of bifacial panels from safeguard relief previously proclaimed in Proclamation 10339, and reinstating the tariff on bifacial panels under the Section 201 Safeguard Action, subject to certain qualifications. These global tariffs are expected to expire in February 2026.

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

Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China, at any point in the supply chain, and may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While this has impacted the U.S. market, AES has managed this issue without significant impact to our projects. Further disruptions may impact our suppliers’ ability or

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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 sectors. On February 10, 2025, President Trump signed Executive Orders modifying existing Section 232 tariffs on steel and aluminum imports to expand their scope of applicability and imposing 25% tariffs on both products. At this time, we do not expect the modifications to tariffs on steel and aluminum to have a material impact on our business. On February 13, 2025, the Trump Administration announced a plan to counter non-reciprocal trading arrangements with all U.S. trading partners by determining the equivalent of a reciprocal tariff with respect to each foreign trade partner. On February 1, 2025, President Trump issued an executive order declaring a national emergency under the International Emergency Economic Powers Act (IEEPA) and imposing a 10% additional tariff on imports from China and on March 4, 2025, this tariff was increased to 20%. We expect that additional 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 United States and we expect limited impact to 2025 and 2026 projects due to the recently announced tariffs on China. Any additional U.S. tariffs on imports from other countries or higher tariffs could negatively impact our business.

The impact of new tariffs, including reciprocal tariffs, or Commerce investigations, the impact of any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the renewable energy supply chain and their effect on AES’ U.S. renewable energy 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 contracted and imported in the U.S. the solar panels that are necessary to complete our U.S. backlog projects scheduled to finish construction and become operational in 2025 and 2026. Additionally, we have secured and imported in the U.S. the majority of the batteries needed for our energy storage projects scheduled to be completed in 2025 and we have contracted with U.S. or Korean- manufacturers for sufficient volume of batteries for our storage projects scheduled to be completed in 2026. For our U.S. wind projects scheduled to be completed in 2025 and 2026, we have contracted with U.S. and non-Chinese manufacturers to meet our supply needs.

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

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

According to the National Oceanic and Atmospheric Administration ("NOAA"), La Niña Conditions are currently observed. La Niña conditions are expected to persist through February-April 2025, with a transition to ENSO-neutral conditions expected during March-May 2025.

In Panama, La Niña phenomenon typically results in more precipitation than historical average conditions, however local system impacts may vary due to other factors. Higher hydrology may result in energy surpluses after covering the contracted hydro positions, available to be sold in the spot market.

In Colombia, La Niña is typically characterized by more rainfall, possibly leading to a decrease in spot prices. However, during La Niña, impacts vary and the basin where Chivor is located may experience more volatility in rainfall than the rest of the system. Inflows at our Chivor hydroelectric plant were below historical averages in the fourth quarter of 2024. Should dry conditions persist, Chivor may be exposed to higher spot prices.

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

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

Macroeconomic and Political

The macroeconomic and political environments in some countries where our subsidiaries conduct business have changed during 2024. 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.

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

Our U.S. renewables business has a backlog of approximately 8.4 GW and 51 GW pipeline that we intend to utilize to continue to grow our business, and these changes in tax policy are supportive of this strategy. We account for U.S. renewables projects according to U.S. GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the investment tax credit begins in the quarter the project is placed in service. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy.

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

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

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

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

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

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

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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 recovering of operations and maintenance costs through the regulatory process, which may have timing impacts on recovery.

Interest Rates — In the U.S. and other markets in which we operate, there has been a rise in interest rates 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 — On July 8, 2024, the Argentine government enacted Law 27,742 or Ley Bases, translated in English as Law of Bases and Starting Points for the Freedom of the Argentine People. Ley Bases declares a public emergency in administrative, economic, financial, and energy matters for a term of one year, grants delegated powers to the President, and contains a broad reform of the State in order to deregulate the economy, including measures such as labor reform, the implementation of the Incentive Regime for Large Investments, and the modification of several non-income tax measures. The law also opens avenues for privatization of state-owned energy companies.

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

On January 28th, 2025, the Energy Secretariat of the Ministry of Economy of the Nation issued Resolution 21/2025, initiating a series of reforms in the Wholesale Electricity Market (MEM) aimed at ensuring a more efficient, competitive, and sustainable electrical system. The transition will be gradual, ensuring that the energy supply remains secure and costs for consumers do not increase. The key elements of this reform process include (a) decentralization of fuel management, allowing thermal generators to manage their own fuel supplies; (b) promotion of free bilateral contracts in the market between generators, large users, and distributors, replacing the current contract regulations; (c) the national government's commitment to honor existing generation and fuel contracts until their completion. If necessary, competitive tenders will be conducted for new infrastructure. These changes aim to gradually normalize the operation of the MEM, eliminate unnecessary restrictions, and create economic incentives that encourage the addition of new generation capacity under competitive conditions.

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 on our consolidated results of operations, cash flows, and financial condition.

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. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was enacted to create a structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for

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adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). PROMESA also expedites the approval of key energy projects and other critical projects in Puerto Rico.

PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Ilumina’s non-recourse debt of $22 million continues to be in technical default and is classified as current as of December 31, 2024. The non-recourse debt at AES Puerto Rico is also in payment default.

In 2022, mediation commenced to resolve the PREPA Title III case. PREPA's plan confirmation mediation was extended to March 24, 2025, and the decision is still pending.

Considering the information available as of the date hereof, management believes the carrying amount of our long-lived assets at AES Puerto Rico of $80 million is recoverable as of December 31, 2024.

Decarbonization Initiatives

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

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

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

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

Regulatory

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

U.S. Executive Orders — A recent Executive Order has required a review of all federal onshore wind leasing and federal permitting practices. In executing this order, the Department of Interior and other agencies have paused federal permitting for all wind projects on federal lands and private lands with a federal nexus, and have also paused federal permitting for solar, storage, and other renewables for 60-days. Our U.S. renewables projects are developed primarily on private land and are designed in a manner that minimizes the potential of a federal nexus. At this time, we do not expect this Order to have a significant impact on our business.

AES Maritza PPA Review — DG Comp is conducting a preliminary review of whether AES Maritza’s PPA with NEK is compliant with the European Union's State Aid rules. No formal investigation has been launched by DG Comp to date. AES Maritza has previously engaged in discussions with the DG Comp case team and the

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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 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 operation, and cash flows. As of December 31, 2024, the carrying value of our long-lived assets at Maritza is $309 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.

Impairments and Realizability

Long-lived Assets and Current Assets Held-for-Sale — During the year ended December 31, 2024, the Company recognized asset impairment expense of $374 million. See Note 23—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. 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 2024 totaled $124 million at December 31, 2024.

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 $232 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.

Capital Resources and Liquidity

Overview

As of December 31, 2024, the Company had unrestricted cash and cash equivalents of $1.5 billion, of which $265 million was held at the Parent Company and qualified holding companies. The Company had $79 million in short-term investments, held primarily at subsidiaries, and restricted cash and debt service reserves of $515 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $22.7 billion

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and $5.7 billion, respectively. Of the $2.7 billion of our current non-recourse debt, $2.5 billion was presented as such because it is due in the next twelve months and $186 million relates to debt considered in default. AES Puerto Rico is in payment default. All other defaults are not payment defaults but are instead technical defaults triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents. Additionally, on February 6, 2025, AES Dominican Renewable Energy failed to comply with a covenant on its debt of $354 million, resulting in a technical default. AES Dominican Renewable Energy is classified as held-for-sale as of December 31, 2024, therefore the associated non-recourse debt is classified in Current held-for-sale liabilities on the Consolidated Balance Sheet. See Note 12—Obligations and Note 25—Held-For-Sale and Dispositions in Item 8.—Financial Statements of this Form 10-K for additional detail. As of December 31, 2024, the Company also had $917 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 $899 million in recourse debt which matures within the next twelve months. Furthermore, we have $616 million due under supplier financing arrangements that have a Parent Company guarantee. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other factors. The amounts involved in any such repurchases may be material.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies, and related assets. Our non-recourse financing is designed to limit cross-default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. 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 $28.8 billion of total gross debt outstanding as of December 31, 2024, approximately $8.9 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, 2024, the total maximum outstanding amount of hedges protecting the company against variable rate exposure was $7.9 billion. These hedges generally provide economic protection through the entire expected life of the projects, regardless of the type of debt issued to finance construction or refinance the projects in the future.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock, and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support in support of tax equity partnerships or 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, 2024, 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 $3.0 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).

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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, 2024, we had $378 million in letters of credit under bilateral agreements, $129 million in letters of credit outstanding provided under our unsecured credit facilities, and $18 million in letters of credit outstanding provided under our revolving credit facilities. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the year ended December 31, 2024, the Parent Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.

Additionally, in connection with certain project financings, some of the Company's subsidiaries have expressly undertaken limited obligations and commitments. These contingent contractual obligations are issued at the subsidiary level and are non-recourse to the Parent Company. As of December 31, 2024, the maximum undiscounted potential exposure to guarantees and letters of credit issued by our subsidiaries was $5.3 billion, including $2.2 billion of customary payment guarantees under EPC contracts and other agreements, $1.4 billion of letters of credit outstanding, $1.2 billion of surety bonds and other guarantees issued by insurance companies, and $388 million of tax equity financing related guarantees.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.

Long-Term Receivables

As of December 31, 2024, the Company had approximately $102 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, 2025, 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 revenues recognized on regulated energy contracts that were impacted by the Stabilization Funds created by the Chilean government. 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, 2024, the Company had approximately $963 million of loans receivable related to the Mong Duong facility in Vietnam, which was constructed under a BOT contract. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25-year term of the plant's PPA. As of December 31, 2024, Mong Duong met the held-for-sale criteria and the loan receivable balance, net of CECL reserve of $23 million, was classified in held-for-sale assets. Of the loan receivable balance, $121 million was classified in Current held-for-sale assets, and $842 million was classified in Noncurrent held-for-sale assets on the Consolidated Balance Sheets. See Note 21—Revenue included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

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Cash Sources and Uses

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.

The primary sources of cash for the Company in the year ended December 31, 2023 were debt financings, cash flows from operating activities, sales to noncontrolling interests, purchases under supplier financing arrangements, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2023 were repayments of debt, capital expenditures, repayments of obligations under supplier financing arrangements, purchases of short-term investments, and acquisitions of business interests.

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

_____________________________

(1)Includes interest capitalized on development and construction of $637 million and $563 million for the years ended December 31, 2024 and 2023, respectively. Of the total capitalized in 2024 and 2023, $577 million and $486 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 $63 million and $270 million effect of exchange rate changes on cash, cash equivalents and restricted cash for the years ended December 31, 2024 and 2023, respectively. The impacts in 2023 are primarily related to the devaluation of the Argentine peso as Argentina's economy was highly inflationary. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Foreign Exchange Rates for further information.

Consolidated Cash Flows

The following table reflects the changes in operating, investing, and financing cash flows for the comparative twelve month periods (in millions):

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Operating Activities

Fiscal Year 2024 versus 2023

Net cash provided by operating activities decreased $282 million for the year ended December 31, 2024, compared to December 31, 2023.

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 changes 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 $120 million, primarily due to higher margin at our Utilities SBU and proceeds from the transfer of U.S. investment tax credits; partially offset by lower margins at our Renewables and Energy Infrastructure SBUs, higher interest expense, and lower interest income.

•Change in working capital decreased $402 million, primarily due to a $522 million increase in accounts receivable resulting from higher billings and the timing of collections and an increase in inventory of $220 million due to higher coal consumption in the prior year; partially offset by a $153 million decrease in prepaid expenses and other assets due to proceeds from interest rate swap settlements, insurance recoveries, and VAT recoveries as well as the collection of Stabilization Fund receivables in Chile, partially offset by additional lease options and long-term security deposits in the current year at ACED.

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Investing Activities

Fiscal Year 2024 versus 2023

Net cash used in investing activities decreased $488 million for the year ended December 31, 2024 compared to December 31, 2023.

Investing Cash Flows

(in millions)

•Acquisitions of business interests decreased $296 million, primarily due to the prior year acquisitions of Rexford at AES Renewable Holdings for $228 million, Bellefield at ACED for $165 million, and Bolero Solar Park in Chile for $114 million; partially offset by the current year acquisitions of Atacama Solar in Chile for $105 million and various acquisitions of renewables development projects at ACED in the current year totaling $79 million.

•Proceeds from sales of business interests increased $169 million, primarily due to proceeds of $412 million, net of transaction costs and cash sold, from the sale of AES Brasil; partially offset by the prior year selldowns of our ownership interests in Fluence for $156 million and in sPower OpCo B for $98 million.

•Cash from short-term investing activities decreased $403 million, primarily driven by a decrease of $363 million in Brazil due to lower cash requirements for capital expenditures and the sale of AES Brasil in October 2024.

•Capital expenditures decreased $332 million, discussed further below.

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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 $322 million, primarily driven by lower expenditures in Brazil of $406 million primarily due to completion of the Cajuina wind projects in the prior year and the sale of AES Brasil in October 2024, and a $246 million decrease in expenditures for U.S. renewables projects compared to the prior year; partially offset by higher expenditures at our U.S. utilities of $187 million mainly due to higher transmission and distribution project investments, and higher expenditures in Chile of $121 million due to new solar project development.

•Maintenance expenditures decreased $11 million, primarily due to lower expenditures in Brazil of $40 million primarily due to completion of the Cajuina wind projects in the prior year and the sale of AES Brasil in October 2024; partially offset by higher expenditures of $32 million at Southland due to the extension of compliance dates for the OTC units.

•Environmental expenditures increased $1 million, with no material drivers.

Financing Activities

Fiscal Year 2024 versus 2023

Net cash provided by financing activities decreased $442 million for the year ended December 31, 2024 compared to December 31, 2023.

Financing Cash Flows

(in millions)

See Notes 12—Obligations and 18—Equity in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant transactions.

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•The $691 million impact from sales to noncontrolling interests is primarily due to a $210 million decrease in proceeds received at AES Clean Energy from the sales of ownership in project companies to tax equity investors, the prior year sales of a 20% interest in AES Dominicana for $192 million and a 35% interest in Colon for $140 million, and a $146 million decrease in sales under the Chile Renovables renewables partnerships with GIP.

•The $534 million impact from non-recourse revolvers is primarily due to higher net repayments at our Energy Infrastructure and Renewables SBUs.

•The $421 million impact from issuance of preferred shares in subsidiaries is due to $275 million of proceeds received in the prior year from the issuance of preferred shares to GIP as part of the Chile Renovables partnership, and the prior year issuance of $143 million of preferred shares to HASI at AES Renewable Holdings for OpCo 1.

•The $375 million impact from supplier financing arrangements is primarily due to higher net cash outflows at the Renewables SBU; partially offset by higher net cash inflows at the Energy Infrastructure SBU.

•The $904 million impact from non-recourse debt transactions is mainly due to higher net borrowings at the Energy Infrastructure and Utilities SBUs of $236 million and $248 million, respectively, and lower net repayments at AES Hispanola Holdings, BV, and the Renewables SBU of $279 million and $142 million, respectively.

•The $350 million impact from recourse debt is primarily due to the issuance of $1.5 billion of subordinated notes and repayments of $200 million at the Parent Company in the current year; partially offset by the issuance of $900 million of senior notes at the Parent Company in the prior year.

•The $325 million impact from the Parent Company revolver is primarily due to lower net repayments in the current year.

Parent Company Liquidity

The following discussion is included as a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to Cash and cash equivalents, which is determined in accordance with GAAP. Parent Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are dividends and other distributions from our subsidiaries, including refinancing proceeds; proceeds from debt and equity financings at the Parent Company level, including availability under our revolving credit facilities and commercial 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):

The Parent Company paid dividends of $0.69 per outstanding share to its common stockholders during the year ended December 31, 2024. While we intend to continue payment of dividends and believe we will have

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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 $5.7 billion and $4.5 billion as of December 31, 2024 and 2023, respectively. See Note 12—Obligations 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 and other reporting requirements. As of December 31, 2024, 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 $2.7 billion. The portion of current debt related to such defaults was $186 million at December 31, 2024, all of which was non-recourse debt related to three subsidiaries — AES Puerto Rico, AES Ilumina, and AES Jordan Solar. AES Puerto Rico is in payment default. All other defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants or other conditions contained in the non-recourse debt documents. Additionally, on February 6, 2025, AES Dominican Renewable Energy failed to comply with a covenant on its debt of $354 million, resulting in a technical default. AES Dominican Renewable Energy is classified as held-for-sale as of December 31, 2024, therefore the associated non-recourse debt is classified in Current held-for-sale liabilities on the Consolidated Balance Sheet. See Note 12—Obligations and Note 25—Held-For-Sale and Dispositions in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail.

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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, 2024, 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, 2024, 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, 2024 is presented below (in millions):

_____________________________

(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, 2024 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, 2024.

(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 contingent contractual obligations as of December 31, 2024:

Additionally, some of the Company's subsidiaries have contingent contractual obligations that are non-recourse to the Parent Company. As of December 31, 2024, the maximum undiscounted potential exposure to guarantees issued by our subsidiaries was $5.3 billion, including $2.2 billion of customary payment guarantees under EPC

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contracts and other agreements, $1.4 billion of letters of credit outstanding, $1.2 billion of surety bonds and other guarantees issued by insurance companies, and $388 million of tax equity financing related guarantees.

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 2024, 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 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

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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 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

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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 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

112 | 2024 Annual Report

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 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.

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.

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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-K.

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 2024 and accounting pronouncements issued, but not yet effective.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For discussion of the Company's year ended December 31, 2022 compared to the year ended December 31, 2021, refer to Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in Exhibit 99.1 of the Form 8-K filed with the SEC on May 8, 2023.

Executive Summary

In 2023, AES delivered on its strategic and financial objectives. We completed construction or the acquisition of 3.5 GW of renewables and energy storage, and signed long-term PPAs for an additional 5.6 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 loss decreased $323 million, from $505 million to $182 million primarily as a result of favorable contributions at the Utilities, New Energy Technologies, and Renewables SBUs, partially offset by lower contributions from LNG transactions versus 2022 at the Energy Infrastructure SBU.

Adjusted EBITDA, a non-GAAP measure, decreased $119 million, from $2,931 million to $2,812 million, mainly driven by favorable LNG transactions in the prior year, lower contract prices, and higher fixed costs at the Energy Infrastructure SBU; partially offset by favorable weather conditions and new businesses at the Renewables SBU, higher contributions at the Utilities SBU due to the deferral of purchased power costs, higher revenues under a PPA termination agreement at the Energy Infrastructure SBU, and lower losses from affiliates at the New Energy Technologies SBU due to improved margins on a new product line.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $225 million, from $3,198 million to $3,423 million, primarily due to higher realized tax attributes driven by more renewables projects placed in service, as well as impact from the drivers above.

Compared with last year, diluted earnings per share from continuing operations increased $1.16, from a loss of $0.82 in 2022 to earnings of $0.34 in 2023. This increase is mainly driven by lower goodwill impairments in the current year, higher contributions from renewables projects placed in service in the current year, the current year gain on sale of shares in Fluence, and higher contributions at the Utilities SBU due to the deferral of purchased power costs; partially offset by lower contributions from LNG transactions versus 2022, and higher unrealized foreign currency losses at the Energy Infrastructure SBU.

Adjusted EPS, a non-GAAP measure, increased $0.09 from $1.67 to $1.76, mainly driven by higher contributions from renewables projects placed in service in the current year, higher contributions at the Utilities SBU, and lower losses of affiliates at the New Energy Technologies SBU; partially offset by lower contributions from the Energy Infrastructure SBU and higher Parent Company interest.

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Review of Consolidated Results of Operations

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, operations and maintenance costs, depreciation and amortization expenses, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (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.

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Consolidated Revenue and Operating Margin

Year Ended December 31, 2023

Revenue

(in millions)

Consolidated Revenue — Revenue increased $51 million in 2023 compared to 2022, driven by:

•$446 million at Renewables driven by higher spot sales at higher prices, and new projects placed in service; partially offset by unrealized derivative losses; and

•$73 million at New Energy Technologies mainly driven by the sale of the Fallbrook project in March 2023.

These favorable impacts were partially offset by decreases of:

•$368 million at Energy Infrastructure driven by prior year favorable LNG transactions, lower contract energy sales due to lower prices, lower CO2 purchases passed through due to lower production, lower generation, and the impact of the devaluation of the Argentine peso; partially offset by unrealized gains resulting mainly from derivatives as part of our commercial hedging strategy, and higher revenues due to a PPA termination agreement; and

•$122 million at Utilities mainly driven by lower demand due to milder weather in Indiana and Ohio; partially offset by higher TDSIC rider and transmission revenues, and higher demand due to extreme heat in El Salvador.

Operating Margin

(in millions)

Consolidated Operating Margin — Operating margin decreased $44 million, or 2%, in 2023 compared to 2022, driven by:

•$117 million at Energy Infrastructure primarily driven by prior year favorable LNG transactions, lower contract energy sales due to lower prices, lower dispatch driven by lower demand, higher fixed costs, and a prior year one-time revenue recognition driven by a reduction in a project's expected completion costs; partially offset

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by unrealized gains resulting mainly from derivatives as part of our commercial hedging strategy, and higher revenues due to a PPA termination agreement; and

•$36 million at Renewables mainly driven by higher fixed costs due to an accelerated growth plan and unrealized derivative losses; partially offset by new projects placed in service, better hydrology, and higher wind availability, resulting in higher renewable energy generation.

These unfavorable impacts were partially offset by increases of:

•$57 million at Corporate and Other primarily driven by a decrease in reserve for losses and higher premiums earned by the AES self-insurance company; and

•$54 million at Utilities primarily driven by the deferral of purchased power costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, an increase in transmission and TDSIC rider revenues, higher demand due to extreme heat in El Salvador, and a regulatory settlement in the prior year; partially offset by the impact of milder weather in Indiana and Ohio, and higher fixed costs.

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 increased $48 million, or 23%, to $255 million in 2023 compared to $207 million in 2022, primarily due to increased business development activity.

Interest expense

Interest expense increased $202 million, or 18%, to $1.3 billion in 2023, compared to $1.1 billion in 2022, primarily due to new debt issued at the Renewables, Energy Infrastructure, and Utilities SBUs, and a higher weighted average interest rate and debt balance at the Parent Company; partially offset by higher capitalized interest at the Renewables SBU.

Interest income

Interest income increased $162 million, or 42%, to $551 million in 2023, compared to $389 million in 2022 primarily due to higher average interest rates and short-term investments at the Energy Infrastructure and Renewables SBUs and the Parent Company; partially offset by the prior year sales-type lease receivable adjustment at the Alamitos Energy Center.

Loss on extinguishment of debt

Loss on extinguishment of debt increased $48 million to $63 million in 2023, compared to $15 million in 2022. This increase was primarily due to losses of $47 million and $10 million due to prepayments at AES Andes and AES Hispanola Holdings BV, respectively, partially offset by a prior year refinancing at AES Renewable Holdings, resulting in a loss of $12 million.

See Note 11—Debt included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Other income

Other income decreased $13 million, or 13%, to $89 million in 2023, compared to $102 million in 2022 primarily due to the prior year gain on remeasurement of our existing investment in 5B, which is accounted for using the measurement alternative, and the prior year insurance proceeds primarily associated with property damage at TermoAndes; partially offset by the current year gain on remeasurement of contingent consideration at AES Clean Energy.

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Other expense

Other expense increased $31 million, or 46%, to $99 million in 2023, compared to $68 million in 2022 primarily driven by impairments of inventory due to planned early plant closures at Ventanas 2, Norgener, and Warrior Run, as well as higher losses on commencement of sales-type leases at AES Renewable Holdings; partially offset by the prior year costs related to the disposition of AES Gilbert, including the recognition of an allowance on the sales-type lease receivable.

See Note 21—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Gain (loss) on disposal and sale of business interests

Gain on disposal and sale of business interests was $134 million in 2023, primarily due to the gain on sale of shares of Fluence, our equity method investment, compared to a loss of $9 million in 2022.

See Note 8—Investments in and Advances to Affiliates included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Goodwill impairment expense

Goodwill impairment expense was $12 million in 2023 due to a $12 million impairment at the TEG TEP reporting unit primarily driven by an increase in the discount rate due to increasing risk of non-renewal of operating permits required after March 31, 2024.

Goodwill impairment expense was $777 million in 2022 due to a $644 million impairment at AES Andes and a $133 million impairment at AES El Salvador. This was due to the Company seeing increases in inputs utilized to derive the discount rate applied in our goodwill impairment analysis, such as higher interest rates and country risk premiums in certain markets. These changes to the inputs of our discount rate negatively impacted our annual goodwill impairment test as of October 1, 2022.

See Note 9—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Asset impairment expense

Asset impairment expense increased $304 million, or 40%, to $1.1 billion in 2023, compared to $763 million in 2022. This increase was primarily due to a $198 million impairment associated with PJM's approval to retire the Warrior Run coal-fired facility, a $186 million impairment at New York Wind related to a repowering project that will result in decommissioning the existing turbines and reducing their depreciable lives, a $167 million impairment at Mong Duong upon meeting the held-for-sale criteria, $151 million of impairments at AES Clean Energy Development primarily related to the write-off of project development intangibles for projects that were determined to be no longer viable, and a $137 million impairment associated with the commitment to accelerate the retirement of the Norgener coal-fired plant in Chile. This increase was partially offset by the $468 million impairment of Maritza's coal-fired plant in 2022 due to Bulgaria's commitment to cease electricity generation using coal as a fuel-source beyond 2038 and lower impairments at TEG and TEP in Mexico.

See Note 22—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

Foreign currency transaction losses

Foreign currency transaction gains (losses) in millions were as follows:

_____________________________

(1)    Includes peso-denominated energy receivable indexed to the USD through the FONINVEMEM agreement which is considered a foreign currency derivative. See Note 7—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.

(2)    Includes losses of $28 million and $20 million on foreign currency derivative contracts for the years ended December 31, 2023 and 2022, respectively.

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The Company recognized net foreign currency transaction losses of $359 million in 2023, primarily driven by the depreciation of the Argentine peso, unrealized losses related to an intercompany loan denominated in the Colombian peso, and realized and unrealized foreign currency derivative losses in South America due to the depreciating Colombian peso.

The Company recognized net foreign currency transaction losses of $77 million in 2022, primarily driven by the depreciation of the Argentine peso, partially offset by realized foreign currency derivative gains in South America due to the depreciating Colombian peso.

Other non-operating expense

There was no other non-operating expense in 2023. Other non-operating expense was $175 million in 2022 due to the other-than-temporary impairment of the sPower equity method investment. The impairment analysis was triggered by the signing of a purchase and sale agreement which, at the time, implied an expected loss upon sale of the Company's indirect interest in a portfolio of sPower's operating assets ("OpCo B"). The transaction closed on February 28, 2023. sPower primarily holds operating assets where the tax credits associated with underlying projects have already been allocated to tax equity investors. The application of HLBV accounting increases the carrying value of these investments, as earnings are initially disproportionately allocated to the sponsor entity. Since sPower does not have any ongoing development or other value creation activities following the transfer of these activities to AES Clean Energy Development, the impairment adjusts the carrying value to the fair market value of the operating assets. See Note 25—Acquisitions included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information regarding the formation of AES Clean Energy Development.

See Note 8—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 expense was $261 million in 2023 compared to $265 million in 2022. The Company's effective tax rates were 251% and (157)% for the years ended December 31, 2023 and 2022, respectively.

The 2023 effective tax rate was impacted by noncontrolling interest in U.S. tax-equity partnerships and pretax impairments at certain Mexican subsidiaries and at the Mong Duong coal-fired plant in Vietnam. These impacts were partially offset by inflationary and foreign currency impacts at certain Argentine businesses, net of valuation allowances, as well as the recognition of U.S. investment tax credits for renewables projects placed in service this year. See Note 22—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for details of the asset impairments.

The 2022 effective tax rate was impacted by the nondeductible goodwill impairments at AES Andes and AES El Salvador, as well as the asset impairment of the Maritza coal-fired plant. These impacts were partially offset by favorable LNG transactions at the Energy Infrastructure SBU and inflationary and foreign currency impacts at certain Argentine businesses recognized in 2022. See Note 9—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for details of the goodwill impairments. See Note 22—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for details of the asset impairments.

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 23—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 decreased $39 million, or 55%, to $32 million in 2023, compared to $71 million in 2022. This decrease was primarily driven by an increase in earnings from Mesa La Paz, primarily due the termination of unrealized derivatives due to a contract amendment, and by a decrease in losses from Fluence, mainly attributable to improved margins on a new product line and reduced shipping constraints and transportation

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costs. This decrease in losses was partially offset by lower earnings from sPower, mainly due to lower earnings from renewables projects that came online.

See Note 8—Investments In and Advances to Affiliates 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 income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $472 million to a $431 million loss in 2023, compared to income of $41 million in 2022. This decrease was primarily due to:

•Increased costs associated with the growth of our business and higher allocation of losses to tax equity investors on projects placed in service at the Renewables SBU;

•Impairment at Mong Duong upon meeting the held-for-sale criteria in the current year;

•Prior year one-time revenue recognition driven by a reduction in a project's expected completion costs at the Energy Infrastructure SBU; and

•Lower earnings from the Utilities SBU due to unfavorable weather conditions.

These drivers were partially offset by:

•Higher earnings from the Renewables SBU due to favorable weather conditions; and

•Higher allocation of earnings at Southland Energy to noncontrolling interests.

Net income (loss) attributable to The AES Corporation

Net income attributable to The AES Corporation increased $795 million to $249 million in 2023, compared to a loss of $546 million in 2022. This increase was primarily due to:

•Lower goodwill impairments in the current year;

•Higher contributions from renewables projects placed in service in the current year;

•Prior year other-than-temporary impairment of our investment in sPower;

•Gain on sale of shares in Fluence in the current year;

•Increase in interest income due to higher average interest rates and short term investments at the Energy Infrastructure and Renewables SBUs;

•Higher earnings from the Utilities SBU due to the deferral of previously recognized purchased power costs and a prior year charge resulting from a regulatory settlement; and

•Lower losses from affiliates at the New Energy Technologies SBU.

These increases were partially offset by:

•Higher unrealized foreign currency losses at the Energy Infrastructure SBU;

•Higher long-lived asset impairments in the current year;

•Lower earnings from the Energy Infrastructure SBU due to prior year favorable LNG transactions, lower contract energy sales due to lower prices, lower thermal dispatch, and higher fixed costs; and

•Increase in interest expense due to higher interest rates and new debt issued at the Renewables and Energy Infrastructure SBUs, and a higher Parent Company weighted average interest rate.

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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 our businesses in Chile); and New Energy Technologies (green hydrogen initiatives and investments in Fluence, Uplight, and 5B). Our businesses in Chile, which have a mix of generation sources, including renewables, are also included within the Energy Infrastructure SBU, as the generation from all sources is pooled to service our existing PPAs. In our 2022 Form 10-K, the management reporting structure and the Company’s reportable segments were mainly organized by geographic regions. In March 2023, we announced internal management changes as a part of our ongoing strategy to align our business to meet our customers’ needs and deliver on our major strategic objectives. The results of our operations are now reported along our four newly formed technology-based SBUs.

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 2023, management began assessing operational performance and making resource allocation decisions using Adjusted EBITDA. Therefore, the Company uses Adjusted EBITDA as its primary segment performance measure. EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes are new non-GAAP supplemental measures reported beginning in the first quarter of 2023.

For the year ended December 31, 2023, the Company changed the definition of Adjusted EPS to remove the adjustment for tax benefit or expense related to the enactment effects of 2017 U.S. tax law reform and related regulations and any subsequent period adjustments related to enactment effects, including the 2021 tax benefit on reversal of uncertain tax positions effectively settled upon the closure of the Company's U.S. tax return exam. As this adjustment was specific to the impacts of tax law reform enacted in 2017, we believe removing this adjustment from our non-GAAP definition provides simplification and clarity for our investors. There were no such impacts in 2022 or 2023.

EBITDA, Adjusted EBITDA and Adjusted EBITDA with Tax Attributes

We define EBITDA as earnings before interest income and expense, taxes, depreciation, and amortization. We define Adjusted EBITDA as EBITDA adjusted for the impact of NCI and interest, taxes, depreciation, and amortization of our equity affiliates, adding back interest income recognized under service concession arrangements, and excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions and equity securities; (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; and (f) 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.

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 related to derivative transactions or equity securities

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remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or retire debt, the non-recurring nature of the impact of the early contract terminations at Angamos, 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.

_____________________________

(1)The allocation of earnings and losses to tax equity investors from both consolidated entities and equity affiliates is removed from Adjusted EBITDA.

(2)         Adjusted EBITDA with Tax Attributes includes the impact of the share of the ITCs, PTCs, and depreciation deductions allocated to tax equity investors under the HLBV accounting method and recognized as Net loss (income) attributable to noncontrolling interests and redeemable stock of subsidiaries on the 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 related to derivative transactions and equity securities; (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; and (f) 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. 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 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 related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or retire debt, and the non-recurring nature of the impact of the early contract terminations at Angamos, 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.

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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 related to derivative transactions and equity securities; (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, 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; and (f) 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.

The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company's internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or retire debt, and the non-recurring nature of the impact of the early contract terminations at Angamos, 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 a loss from continuing operations of $0.82 for the year ended December 31, 2022. For purposes of measuring diluted loss per share under GAAP, common stock equivalents were excluded from weighted average shares as their inclusion would be anti-dilutive. However, for purposes of computing Adjusted EPS, the Company has included the impact of dilutive common stock equivalents. The table below reconciles the weighted average shares used in GAAP diluted loss per share to the weighted average shares used in calculating the non-GAAP measure of Adjusted EPS.

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_____________________________

(1)Amount primarily relates to unrealized derivative losses due to the termination of a PPA of $72 million, or $0.10 per share and net unrealized derivative losses at AES Clean Energy of $20 million, or $0.03 per share, offset by net unrealized derivative gains at the Energy Infrastructure SBU of $46 million, or $0.06 per share.

(2)Amount primarily relates to unrealized losses on power swaps at Southland Energy of $109 million, or $0.15 per share.

(3)Amount primarily relates to unrealized foreign currency losses in Argentina of $262 million, or $0.37 per share, mainly associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized foreign currency losses at AES Andes of $25 million, or $0.03 per share.

(4)Amount primarily relates to unrealized foreign currency losses in Argentina of $39 million, or $0.05 per share, mainly associated with the devaluation of long-term receivables denominated in Argentine pesos.

(5)Amount primarily relates to the gain on sale of Fluence shares of $136 million, or $0.19 per share, partially offset by costs due to early plant closure at the Ventanas 2 and Norgener coal-fired plants in Chile of $37 million, or $0.05 per share and at Warrior Run of $6 million, or $0.01 per share, and day-one losses recognized at commencement of sales-type leases at AES Renewable Holdings of $20 million, or $0.03 per share.

(6)Amount primarily relates to costs on disposition of AES Gilbert, including the recognition of an allowance on the sales-type lease receivable, of $13 million, or $0.02 per share, and a day-one loss recognized at commencement of a sales-type lease at AES Waikoloa Solar of $5 million, or $0.01 per share.

(7)Amount primarily relates to asset impairments at Warrior Run of $198 million, or $0.28 per share, at New York Wind of $139 million, or $0.20 per share, the Norgener coal-fired plant in Chile of $136 million, or $0.19 per share, at TEG and TEP of $76 million and $58 million, respectively, or $0.19 per share, AES Clean Energy development projects of $114 million, or $0.16 per share, at Mong Duong of $88 million, or $0.12 per share, at Jordan of $21 million, or $0.03 per share, and at the GAF Projects at AES Renewable Holdings of $18 million, or $0.03 per share, and a goodwill impairment at the TEG TEP reporting unit of $12 million, or $0.02 per share.

(8)Amount primarily relates to goodwill impairments at AES Andes of $644 million, or $0.91 per share, and at AES El Salvador of $133 million, or $0.19 per share, other-than-temporary impairment at sPower of $175 million, or $0.25, as well as long-lived asset impairments at Maritza of $468 million, or $0.66 per share, at TEG TEP of $191 million, or $0.27 per share, and in Jordan of $28 million, or $0.04 per share.

(9)Amount primarily relates to losses incurred at AES Andes due to early retirement of debt of $46 million, or $0.07 per share, and loss on early retirement of debt at AES Hispanola Holdings BV of $10 million, or $0.01 per share.

(10)Amount primarily relates to losses on early retirement of debt due to refinancing at AES Renewable Holdings of $12 million, or $0.02 per share, at AES Clean Energy of $5 million, or $0.01 per share, at Mong Duong of $4 million, or $0.01 per share, and at TEG TEP of $4 million, or $0.01 per share.

(11)Amount primarily relates to income tax benefits associated with the asset impairments at Warrior Run of $46 million, or $0.06 per share, at the Norgener coal-fired plant in Chile of $37 million, or $0.05 per share, at New York Wind of $32 million, or $0.05 per share, at TEG and TEP of $27 million, or $0.04 per share, and at AES Clean Energy development projects of $26 million, or $0.04 per share; income tax benefits associated with the recognition of unrealized losses due to the termination of a PPA of $17 million, or $0.02 per share; and income tax benefits associated with losses incurred at AES Andes due to early retirement of debt of $13 million, or $0.02 per share; partially offset by income tax expense associated with the gain on sale of Fluence shares of $31 million, or $0.04 per share.

(12)Amount primarily relates to income tax benefits associated with the impairment at Maritza of $48 million, or $0.07 per share, income tax benefits associated with the other-than-temporary impairment at sPower of $39 million, or $0.06 per share, income tax benefits associated with the impairment at TEG TEP of $34 million, or $0.05 per share, and income tax benefits associated with unrealized losses on power swaps at Southland Energy of $24 million, or $0.03 per share.

Renewables SBU

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

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(1)    A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

Operating Margin decreased $36 million driven primarily by higher fixed costs due to an accelerated growth plan and unrealized derivative losses. This decrease was partially offset by better hydrology, new businesses operating in our portfolio, and higher wind availability, resulting in higher renewable energy generation.

Adjusted EBITDA increased $40 million primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, and depreciation expense.

Adjusted EBITDA with Tax Attributes increased $366 million, primarily due to higher realized tax attributes driven by more projects being placed in service, as well as impact from the increase in Adjusted EBITDA. For the

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year ended December 31, 2023 and 2022, we realized $593 million and $267 million, respectively, from tax attributes earned by AES Clean Energy businesses.

Utilities SBU

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

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(1)    A non-GAAP financial measure. See SBU 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 $54 million mainly driven by the deferral of purchased power costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, an increase in transmission and TDSIC rider revenues, higher demand due to extreme heat in El Salvador, and a regulatory settlement in the prior year, partially offset by the impact of milder weather in Indiana and Ohio, higher fixed costs, and increased depreciation expense.

Adjusted EBITDA increased $66 million primarily due to the drivers above, adjusted for NCI and depreciation expense, partially offset by an increase in defined benefit plan costs.

Adjusted EBITDA with Tax Attributes increased $84 million due to the drivers above, as well as $18 million of realized tax attributes related to the Hardy Hills solar project in the current year.

Adjusted PTC increased $65 million primarily due to the drivers above, partially offset by higher depreciation expense.

Energy Infrastructure SBU

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

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(1)    A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

Operating Margin decreased $117 million, driven primarily by lower LNG transactions, lower contract energy sales due to lower prices, lower dispatch driven by lower demand, higher fixed costs, and a prior year one-time revenue recognition driven by a reduction in a project's expected completion costs.

The decrease in Operating Margin is partially offset by unrealized gains resulting mainly from derivatives as part of our commercial hedging strategy, higher revenues due to a PPA termination agreement, lower outages, and lower depreciation expense due to impairments recognized in the current and prior year.

Adjusted EBITDA decreased $305 million, primarily due to the drivers above adjusted for NCI, unrealized derivative gains, and depreciation, as well as higher realized foreign currency losses and lower insurance recovery.

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New Energy Technologies SBU

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

_____________________________

(1)    A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business for the respective ownership interest for key businesses.

Operating Margin decreased $2 million, with no material drivers.

Adjusted EBITDA increased $54 million, primarily driven by lower losses at Fluence due to improved margins on a new product line, the settlement of contractual claims with a battery module vendor, and incremental shipping and transportation costs incurred in the prior year as a result of COVID-19. These increases were partly offset by higher costs for research and development, sales and marketing, and general and administrative expenses.

Key Trends and Uncertainties

During 2024 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, 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 — On March 29, 2022, the U.S. Department of Commerce (“Commerce”) announced the initiation of an investigation into whether imports into the U.S. of solar cells and panels imported from Cambodia, Malaysia, Thailand, and Vietnam (“Southeast Asia”) are circumventing antidumping and countervailing duty (“AD/CVD”) orders on solar cells and panels from China. This investigation resulted in significant systemic disruptions to the import of solar cells and panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any circumvention duties on imported solar cells and panels from Southeast Asia that result from this investigation for a 24-month period ending June 6, 2024. Suppliers resumed importing cells and panels from Southeast Asia into the U.S. pursuant to a Commerce certification regime implementing the Proclamation.

On December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four Southeast Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to many but not all of these companies. Additionally, Commerce issued a preliminary determination that circumvention would not be deemed to occur for any solar cells and panels imported from the four countries if the wafers were manufactured outside of China or if no more than two out of six specifically identified components were produced in China. On August 18, 2023, Commerce issued its final determinations on the matter and affirmed its preliminary findings in most respects. Additionally, Commerce found that three of the specific companies it investigated were not circumventing.

On December 29, 2023, Auxin Solar and Concept Clean Energy filed a lawsuit with the U.S. Court of International Trade, challenging certain aspects of the final rule promulgated by Commerce to implement the Proclamation. The lawsuit specifically challenges Commerce’s decisions not to suspend the final disposition of certain entries of imported solar cells and panels from Southeast Asia made prior to June 6, 2024, and not to collect AD/CVD deposits with respect to those entries. The Department of Justice has responded by filing a motion to dismiss the lawsuit.

Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China and may lead to certain suppliers being blocked from importing solar cells

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and panels to the U.S. While this has impacted the U.S. market, AES has managed this issue without significant impact to our projects. Further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements or to continue to supply cells or panels into the U.S. market on terms that we deem satisfactory.

The impact of any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the solar panel supply chain and their effect on AES’ U.S. solar project development and construction activities remain uncertain. AES will continue to monitor developments and take prudent steps towards maintaining a robust supply chain for our renewables projects.

We have contracted and secured our expected requirements for solar panels for U.S. projects targeted to achieve commercial operations in 2024.

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. In the past, dry hydrological conditions in Panama, Brazil, Colombia and Chile have presented challenges for our businesses in these markets. Low rainfall and water inflows have caused reservoir levels to be below historical levels, reduced generation output, and 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 a material adverse impact on our results of operations. As a mitigation measure, AES has invested in thermal, wind, and solar generation assets, which have a complementary profile to hydroelectric plants. These plants are expected to have a higher generation in low hydrology scenarios, which allows them to generate additional revenues from the spot that offset purchases on the hydroelectric side.

According to the National Oceanic and Atmospheric Administration ("NOAA"), El Niño conditions are observed and forecasted through the beginning of Q2 of 2024. Hydrological conditions thereafter are uncertain, but indications suggest either a return to normalized patterns or an emergence of La Niña for the remainder of 2024. In Panama, consistent with expected El Niño impacts, local hydrological forecasts indicate below historical average inflows persisting into Q2 of 2024, which could impact our results of operations. AES reduced its total generation exposure in Panama to dry hydrological conditions through investments in such complementary assets as the Colon LNG power facility, which commenced operations in 2018, the Penonome Wind Farm, and solar projects, providing a stable and independent diversified energy supply during periods of drought or when hydroelectric generation is limited. In Panama, the La Niña phenomenon in contrast to El Niño typically means wetter conditions than average, although local system impacts may vary due to other factors. Higher hydrology may result in energy surpluses after covering the contracted hydro positions, available to be sold in the spot market after fulfilling contract obligations.

In Brazil, El Niño generally means more rainfall in the South and higher temperatures in the central region of the country, as seen in the last quarter of 2023, while La Niña results in more rainfall in the North, drier conditions in the South and milder temperatures in the central region, which could result in lower demand. Current system reservoir levels are high which supports continued lower spot prices through 2024 mitigating hydrological risk – lower prices limit external thermal generation which, if dispatched, could impact demand for the AES hydro generation. In Colombia, El Niño is characterized by drought and may result in higher spot prices. Lower overall AES Chivor hydrology may result in increased spot price energy exposure to cover contracted positions. The basin where AES Chivor is located typically experiences wet conditions from June through September in contrast with the broader system, which can result in additional energy available to sell in the spot market after fulfilling contract obligations as experienced earlier in 2023. La Niña in Colombia is characterized by more rainfall possibly leading to a decrease in spot prices. However, during La Niña impacts vary and the basin where Chivor is located may experience drier conditions than the system, notably between June and September. In Chile, the primary driver for AES’ hydro assets is snowpack volumes. Lower snowpack, together with reduced rainfall in the system, could increase both spot prices and energy purchase volumes required to meet contracted positions.

The exact behavior pattern and strength of El Niño and the potential evolution towards La Niña cannot be definitively known at this time and therefore the impacts could vary from those described above, and may include impacts to our businesses beyond hydrology, including with respect to power generation from other renewable sources of energy and demand. Even if rainfall and water inflows return to or exceed historical averages, in some cases high market prices and low generation could persist until reservoir levels are fully recovered. Further, investments made in thermal, wind, and solar power generation may benefit from uncontracted spot sales at higher market prices. Our thermal assets in Panama may alternatively be impacted by low dispatch due to low market prices in the event of a La Niña. Impacts may be material to our results of operations.

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Macroeconomic and Political

The macroeconomic and political environments in some countries where our subsidiaries conduct business have changed during 2023. 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.

Argentina — The recent election of President Javier Milei on December 10, 2023, marks a pivotal moment in Argentina's economic landscape. The entering administration issued Decree No. 55/23, signaling a commitment to total economic deregulation. This decree declares a state of emergency in the power sector, tariff revisions for electric power and natural gas transport and distribution, and a broader proposal for sector-wide reform.

President Milei also proposed a new bill, currently under review by Congress, that seeks to overhaul the energy regulatory framework. Emphasizing deregulation, the bill opens avenues for privatization of state-owned energy companies. These proposed 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.

Inflation Reduction Act and U.S. Renewable Energy Tax Credits — The Inflation Reduction Act (the “IRA”) was signed into law in the United States. The IRA includes provisions that are expected to benefit the U.S. clean energy industry, including increases, extensions, direct transfers and/or new tax credits for onshore and offshore wind, solar, storage and hydrogen projects. We expect that the extension of the current solar investment tax credits ("ITCs"), as well as higher credits available for projects that satisfy wage and apprenticeship requirements, will increase demand for our renewables products.

Our U.S. renewables business has a 51 GW pipeline that we intend to utilize to continue to grow our business, and these changes in tax policy are supportive of this strategy. We account for U.S. renewables projects according to U.S. GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the investment tax credit begins in the quarter the project is placed in service. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy.

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

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

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

Global Tax — The macroeconomic and political environments in the U.S. and in some countries where our subsidiaries conduct business have changed during 2022 and 2023. This could result in significant impacts to future tax law. In the U.S., the IRA includes a 15% corporate alternative minimum tax based on adjusted financial statement income. Additional guidance is expected to be issued in 2024.

In the fourth quarter of 2022, the European Commission adopted an amended Directive on Pillar 2 establishing a global minimum tax at a 15% rate. The adoption requires EU Member States to transpose the Directive into their respective national laws by December 31, 2023 for the rules to come into effect as of January 1, 2024. During 2023, the Netherlands, Bulgaria and Vietnam adopted legislation to implement Pillar 2 effective as of January 1, 2024. We will continue to monitor the issuance of draft legislation in other non-EU countries where the Company operates that are considering Pillar 2 amendments. The impact to the Company remains unknown but may be material.

Inflation — In the markets in which we operate, there have been higher rates of inflation recently. While most of our contracts in our international businesses 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

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projects that could negatively impact their competitiveness. Our utility businesses do allow for recovering of operations and maintenance costs through the regulatory process, which may have timing impacts on recovery.

Interest Rates — In the U.S. and other markets in which we operate, there has been a rise in interest rates 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.

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. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

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

PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017. As a result of the bankruptcy filing, AES Puerto Rico and AES Ilumina’s non-recourse debt of $143 million and $25 million, respectively, continue to be in technical default and are classified as current as of December 31, 2023. The non-recourse debt at AES Puerto Rico is also in payment default.

On April 12, 2022, a mediation team was appointed to prepare the plan to resolve the PREPA Title III case and related proceedings. A disclosure statement hearing was held on April 28, 2023. The mediation was extended through August 4, 2023. On November 14, 2023, the Judge presiding over the case approved the supplemental disclosure statement for PREPA’s Fourth Modified Third Amended Title III Plan of Adjustment. The

confirmation trial is still scheduled to begin March 4, 2024.

Earlier this year, AES Puerto Rico took certain measures to address identified liquidity challenges. On July 6, 2023, PREPA agreed to the release of funds in the escrow account guaranteeing AES Puerto Rico’s obligations under the Power Purchase and Operating Agreement (“PPOA”) in order to provide additional liquidity for the business. AES Puerto Rico continues to work with PREPA and its noteholders on these liquidity challenges. During Q4 2023, a restructuring support agreement was executed by AES Puerto Rico and its noteholders and a PPOA amendment was approved by PREPA. These agreements require Puerto Rico Energy Bureau ("PREB") approval to become effective. On February 2, 2024 a resolution was issued by PREB approving the PPOA amendment subject to the incorporation of certain additional terms and conditions. The Company expects the PPOA amendment and restructuring support agreement to become effective during the first quarter of 2024.

Despite these challenges and considering the information available as of the filing date, management believes the carrying amount of our long-lived assets at AES Puerto Rico of $76 million is recoverable as of December 31, 2023.

Mexico Migration and Wheeling Tariffs — The interconnection agreements for TEP and TEG under the self-supply energy regime in Mexico expire in March and April 2024, respectively. Consequently, TEG and TEP are required to migrate into the new energy regime established by the Electricity Industry Law of 2021 (“LIE”) and to execute new interconnection agreements prior to the expiration of the current interconnection agreements. In February and September 2022, respectively, TEG and TEP made formal requests to the Mexican Comision Reguladora de Energia (“CRE”) to update the projects’ permits and allow them to migrate into the LIE (“Migration Requests”).

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In discussions with TEG and TEP, CRE has stated that it will not allow migration into the LIE unless the projects withdraw their respective legal challenges to certain laws, including RES/894/2020 (“Resolution 894”), which attempts to increase the wheeling tariffs paid by TEG and TEP to CFE. The increase is currently estimated to be over $90 million for the relevant period (July 2020 through March 2024). TEG and TEP have informed CRE that the agency is not entitled to reject the Migration Requests because of the legal challenges. In February 2024, the Collegiate Court ruled in favor of TEG and TEP on their challenge to Resolution 894. Nevertheless, later in February 2024, CRE denied TEG's Migration Request. TEG has formally requested that CRE issue a new permit. If CRE does not issue a new permit and if TEG cannot enter into a new interconnection agreement, TEG will not be allowed to operate after its current interconnection agreement expires. CRE is expected to determine TEP's Migration Request in the near future, but we cannot predict the outcome of that determination.

TEG and TEP will take all necessary regulatory and legal steps to protect their interests. Furthermore, if TEG and TEP are ever required to pay increased wheeling tariffs, TEG and TEP will seek to enforce their respective contractual rights to pass-through the increases to their respective offtakers. However, there are no assurances that TEG and TEP will be successful in these efforts. The inability to migrate into the LIE and/or the inability to pass-through wheeling tariff increases could have a material adverse impact on our results of operations.

Decarbonization Initiatives

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

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

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

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

Regulatory

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

We do not believe termination of the PPA is justified. Nevertheless, the PPA Discussions involved a range of potential outcomes, including but not limited to the termination of the PPA and payment of some level of compensation to AES Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict whether and when the PPA Discussions might resume or the outcome of any such discussions. Nor can we predict how DG Comp might resolve its review if the PPA Discussions do not resume or if any such discussions fail to result in an agreement concerning the agency's review. AES Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurance that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of operation, and cash flows. As of December 31, 2023, the carrying value of our long-lived assets at Maritza is $345 million.

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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.

Impairments

Long-lived Assets and Current Assets Held-for-Sale — During the year ended December 31, 2023, the Company recognized asset impairment expense of $1.1 billion. See Note 8—Investments and Advances to Affiliates and Note 22—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information. 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 2023 totaled $1.3 billion at December 31, 2023.

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.

Goodwill — An increase in the discount rate at TEG TEP has negatively impacted our annual goodwill impairment test as of October 1, 2022, and thus, an impairment of goodwill of $12 million has been recognized as of December 31, 2023, reducing the goodwill balance of TEG TEP to zero. See Note 9—Goodwill and Other Intangibles Assets included in Item 8.—Financial Statements and Supplementary Data for further information.

The Company had no other reporting units considered to be “at risk,” as the fair value of all other reporting units exceeded their carrying amounts by more than 10%. Should the fair value of any of the Company’s reporting units fall below its carrying amount as a result of these inputs or other changes such as reduced operating performance, market declines, changes in the discount rate, regulatory changes, or other adverse conditions, goodwill impairment charges may be necessary in future periods.

Capital Resources and Liquidity

Overview

As of December 31, 2023, the Company had unrestricted cash and cash equivalents of $1.4 billion, of which $33 million was held at the Parent Company and qualified holding companies. The Company had $395 million in short-term investments, held primarily at subsidiaries, and restricted cash and debt service reserves of $564 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $22.1 billion and $4.5 billion, respectively. Of the $3.9 billion of our current non-recourse debt, $3.6 billion was presented as such because it is due in the next twelve months and $325 million relates to debt considered in default. Defaults at AES Puerto Rico are covenant and payment defaults. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for additional detail. All other defaults are not payment defaults but are instead technical defaults triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents. As of December 31, 2023, the Company also had $974 million outstanding related to supplier financing arrangements.

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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 $200 million in recourse debt which matures within the next twelve months, as well as amounts due under supplier financing arrangements, of which $814 million has a Parent Company guarantee. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other factors. The amounts involved in any such repurchases may be material.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies, and related assets. Our non-recourse financing is designed to limit cross-default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company's only material unhedged exposure to variable interest rate debt relates to $200 million in senior unsecured term loans. 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 $27 billion of total gross debt outstanding as of December 31, 2023, approximately $9.9 billion accrues interest at variable rates. Brazil holds $2.3 billion of our floating rate non-recourse exposure as variable rate instruments act as a natural hedge against inflation in Brazil. 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, 2023, the total maximum outstanding amount of hedges protecting the company against variable rate exposure was $6.6 billion. These hedges generally provide economic protection through the entire expected life of the projects, regardless of the type of debt issued to finance construction or refinance the projects in the future.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock, and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support in support of tax equity partnerships or 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, 2023, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $4 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).

Some counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. As of December 31, 2023, we had $235 million in letters of credit under bilateral agreements, $188 million in letters of credit outstanding provided under our unsecured credit facilities, and $124 million in letters of credit outstanding provided under our revolving credit facility. These letters of

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credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the year ended December 31, 2023, the Parent Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.

Additionally, in connection with certain project financings, some of the Company's subsidiaries have expressly undertaken limited obligations and commitments. These contingent contractual obligations are issued at the subsidiary level and are non-recourse to the Parent Company. As of December 31, 2023, the maximum undiscounted potential exposure to guarantees issued by our subsidiaries was $2.8 billion, including $1.8 billion of customary payment guarantees under EPC contracts and other agreements, and $1 billion of tax equity financing related guarantees. In addition, as of December 31, 2023, our subsidiaries had $359 million of letters of credit outstanding.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.

Long-Term Receivables

As of December 31, 2023, the Company had approximately $193 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, 2024, or one year from the latest balance sheet date. Noncurrent receivables in the U.S. pertain to the Warrior Run PPA termination agreement and the sale of the Redondo Beach land. The receivables in Chile pertain primarily to revenues recognized on regulated energy contracts that were impacted by the Stabilization Fund created by the Chilean government. 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, 2023, the Company had approximately $1.1 billion of loans receivable related to the Mong Duong facility in Vietnam, which was constructed under a BOT contract. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25-year term of the plant's PPA. As of December 31, 2023, Mong Duong met the held-for-sale criteria and the loan receivable balance, net of CECL reserve, was classified in held-for-sale assets. Of the loan receivable balance, $108 million was classified as Current held-for-sale assets, and $962 million was classified as Noncurrent held-for-sale assets. See Note 20—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, 2023 were debt financings, cash flows from operating activities, sales to noncontrolling interests, purchases under supplier financing arrangements, and sales of short-term investments. The primary uses of cash in the year ended December 31, 2023 were repayments of debt, capital expenditures, repayments of obligations under supplier financing arrangements, purchases of short-term investments, and acquisitions of business interests.

The primary sources of cash for the Company in the year ended December 31, 2022 were debt financings, cash flows from operating activities, sales of short-term investments, purchases under supplier financing

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arrangements, and sales to noncontrolling interests. The primary uses of cash in the year ended December 31, 2022 were repayments of debt, capital expenditures, purchases of short-term investments, acquisitions of noncontrolling interests, and purchases of emissions allowances in Bulgaria.

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

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(1)Includes the $270 million and $56 million effect of exchange rate changes on cash, cash equivalents and restricted cash for the years ended December 31, 2023 and 2022, respectively. These impacts are primarily related to the devaluation of the Argentine peso as Argentina's economy continued to be highly inflationary. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Foreign Exchange Rates for further information.

Consolidated Cash Flows

The following table reflects the changes in operating, investing, and financing cash flows for the comparative twelve month periods (in millions):