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

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

The condensed consolidated financial statements included in Item 1.—Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our 2022 Form 10-K.

Forward-Looking Information

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations, that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. These statements include, but are not limited to, statements regarding management’s intents, beliefs, and current expectations and typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “forecast,” “target,” “will,” “would,” “intend,” “believe,” “project,” “estimate,” “plan,” and similar words. Forward-looking statements are not intended to be a guarantee of future results, but instead constitute current expectations based on reasonable assumptions. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A.—Risk Factors of this Form 10-Q, Item 1A.—Risk Factors and Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Form 10-K and subsequent filings with the SEC.

Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.

Overview of Our Business

We are a diversified power generation and utility company organized into the following four SBUs, mainly organized by technology: Renewables (solar, wind, energy storage, and hydro), Utilities (AES Indiana, AES Ohio, and AES El Salvador), Energy Infrastructure (natural gas, LNG, coal, pet coke, diesel, and oil), and New Energy Technologies (green hydrogen, 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. For additional information regarding our business, see Item 1.—Business of our 2022 Form 10-K.

We have two lines of business: generation and utilities. Our Renewables, Utilities and Energy Infrastructure SBUs participate in our first business line, generation, in which we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. Our Utilities SBU participates in our second business line, utilities, in which we own and/or operate utilities to generate or purchase, distribute, transmit, and sell electricity to end-user customers in the residential, commercial, industrial, and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market. Our New Energy Technologies SBU includes investments in new and innovative technologies to support leading-edge greener energy solutions.

Executive Summary

Compared with last year, third quarter net income decreased $155 million, from $446 million to $291 million. This decrease is the result of lower contributions from LNG transactions versus 2022 at the Energy Infrastructure SBU, partially offset by favorable contributions at the Utilities, Renewables, and New Energy Technologies SBUs.

Adjusted EBITDA, a non-GAAP measure, increased $59 million, from $931 million to $990 million, mainly driven by higher contributions at the Utilities SBU, favorable weather conditions and new businesses at the Renewables SBU, 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; partially offset by favorable LNG transactions in the prior year at the Energy Infrastructure SBU.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $17 million, from $991 million to $1,008

38 | The AES Corporation | September 30, 2023 Form 10-Q

million primarily due to the drivers above, partially offset by lower realized tax attributes driven by fewer projects placed in service.

Compared with last year, third quarter diluted earnings per share from continuing operations decreased $0.27, from $0.59 to $0.32. This decrease is mainly driven by higher long-lived asset impairments in the current year and lower earnings at the Energy Infrastructure SBU mainly due to unrealized foreign currency losses and prior year favorable LNG transactions; partially offset by higher contributions at the Utilities SBU due to the deferral of power purchase costs, and favorable weather conditions and new businesses at the Renewables SBU.

Adjusted EPS, a non-GAAP measure, decreased $0.03 from $0.63 to $0.60, mainly driven by lower contributions from the Energy Infrastructure SBU, higher Parent Company interest, and a higher adjusted tax rate, partially offset by higher contributions at the Utilities SBU.

Compared with last year, net income for the nine months ended September 30, 2023 decreased $20 million, from $481 million to $461 million. This decrease is the result of lower contributions from LNG transactions versus 2022 at the Energy Infrastructure SBU, partially offset by favorable contributions at the Renewables, Utilities, and New Energy Technologies SBUs.

Adjusted EBITDA, a non-GAAP measure, decreased $51 million, from $2,238 million to $2,187 million, mainly driven by favorable LNG transactions in the prior year and higher cost of sales at the Energy Infrastructure SBU; partially offset by favorable weather conditions and new businesses at the Renewables SBU, higher contributions at the Utilities SBU, 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, decreased $91 million, from $2,347 million to $2,256 million, primarily due to the drivers above and lower realized tax attributes driven by fewer projects placed in service.

Compared with last year, diluted earnings per share from continuing operations for the nine months ended September 30, 2023 decreased $0.02, from $0.50 to $0.48. This decrease is mainly driven by favorable LNG transactions in the prior year, higher unrealized foreign currency losses and higher cost of sales at the Energy Infrastructure SBU; partially offset by lower long-lived asset impairments in the current year, higher contributions at the Utilities SBU due to the deferral of power purchase costs, and lower losses of affiliates at the New Energy Technologies SBU.

Adjusted EPS, a non-GAAP measure, decreased $0.15 from $1.18 to $1.03, mainly driven by lower contributions from the Energy Infrastructure SBU, higher Parent Company interest, and a higher adjusted tax rate, partially offset by higher contributions at the Utilities SBU and lower losses of affiliates at the New Energy Technologies SBU.

39 | The AES Corporation | September 30, 2023 Form 10-Q

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(1) Non-GAAP measure. See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition.
(2) GWh sold in 2022.

40 | The AES Corporation | September 30, 2023 Form 10-Q

Overview of Strategic Performance

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

  • As of today, the Company’s backlog, which consists of projects with signed contracts, but which are not yet operational, is 13,138 MW, including 5,761 MW under construction.

  • In year-to-date 2023, the Company completed the construction or acquisition of 1,314 MW of wind, solar and energy storage and expects to complete a total of 3.5 GW by year-end 2023.

  • In year-to-date 2023, the Company has signed 3,740 MW of contracts for renewables.

  • In September 2023, the Company agreed to minority sell-downs of its businesses in the Dominican Republic and Panama, for a total of $190 million in asset sale proceeds.

Review of Consolidated Results of Operations (Unaudited)

Three Months Ended September 30,Nine Months Ended September 30,
(in millions, except per share amounts)20232022$ change% change20232022$ change% change
Revenue:
Renewables SBU$708$532$17633%$1,744$1,407$33724%
Utilities SBU880994(114)-11%2,7032,674291%
Energy Infrastructure SBU1,8612,126(265)-12%5,2395,553(314)-6%
New Energy Technologies SBU————%75273NM
Corporate and Other2924521%96811519%
Eliminations(44)(49)510%(157)(160)32%
Total Revenue3,4343,627(193)-5%9,7009,5571431%
Operating Margin:
Renewables SBU2221883418%4283874111%
Utilities SBU1607981NM3512807125%
Energy Infrastructure SBU504588(84)-14%1,1201,211(91)-8%
New Energy Technologies SBU(2)(2)——%(8)(5)(3)60%
Corporate and Other585535%1891434632%
Eliminations(24)(16)(8)-50%(70)(31)(39)NM
Total Operating Margin918892263%2,0101,985251%
General and administrative expenses(64)(51)(13)25%(191)(149)(42)28%
Interest expense(326)(276)(50)18%(966)(813)(153)19%
Interest income1441004444%39827012847%
Loss on extinguishment of debt—(1)1-100%(1)(8)7-88%
Other expense(12)(10)(2)20%(38)(51)13-25%
Other income1248NM3680(44)-55%
Gain (loss) on disposal and sale of business interests—1(1)-100%(4)—(4)NM
Asset impairment expense(158)(50)(108)NM(352)(533)181-34%
Foreign currency transaction gains (losses)(100)8(108)NM(209)(60)(149)NM
Income tax expense(109)(145)36-25%(179)(186)7-4%
Net equity in losses of affiliates(14)(26)12-46%(43)(54)11-20%
NET INCOME291446(155)-35%461481(20)-4%
Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries(60)(25)(35)NM(118)(124)6-5%
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION$231$421$(190)-45%$343$357$(14)-4%
Net cash provided by operating activities$1,122$784$33843%$2,309$1,649$66040%

Components of Revenue, Cost of Sales, and Operating Margin — Revenue includes revenue earned from the sale of energy from our utilities and the production and sale of energy from our generation plants, which are classified as regulated and non-regulated*,* respectively, on the Condensed Consolidated Statements of Operations. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.

Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, 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

41 | The AES Corporation | September 30, 2023 Form 10-Q

derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

Operating margin is defined as revenue less cost of sales.

Consolidated Revenue and Operating Margin

Three Months Ended September 30, 2023

Revenue

(in millions)

1148

Consolidated Revenue — Revenue decreased $193 million, or 5%, for the three months ended September 30, 2023, compared to the three months ended September 30, 2022, driven by:

  • $265 million at Energy Infrastructure driven by prior year favorable LNG transactions, lower regulated contract sales and prices, lower CO2 purchases passed through due to lower production, lower generation, and the impact of the depreciation of the Argentine peso; partially offset by realized and unrealized derivative gains, and higher revenues due to a PPA termination agreement; and

  • $114 million at Utilities mainly driven by lower volumes as a result of lower demand due to unfavorable weather, and lower fuel and purchase rider revenues; partially offset by higher TDSIC rider and transmission revenues.

These unfavorable impacts were partially offset by an increase of:

  • $176 million at Renewables mainly driven by higher spot sales at higher prices, new businesses operating in our portfolio, resulting in higher renewable energy generation, and the impact of the appreciation of the Colombian peso; partially offset by unrealized commodity derivative losses.

Operating Margin

(in millions)

2180

Consolidated Operating Margin — Operating margin increased $26 million, or 3%, for the three months ended September 30, 2023, compared to the three months ended September 30, 2022, driven by:

  • $81 million at Utilities mainly driven by the deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, and a regulatory settlement in the prior year; and

42 | The AES Corporation | September 30, 2023 Form 10-Q

  • $34 million at Renewables mainly driven by better hydrology, new businesses operating in our portfolio, resulting in higher renewable energy generation and the impact of the appreciation of the Colombian peso; partially offset by unrealized derivative losses, higher fixed costs due to an accelerated growth plan, and lower contracted energy sales.

These favorable impacts were partially offset by a decrease of:

  • $84 million at Energy Infrastructure mainly driven by prior year favorable LNG transactions; partially offset by higher revenues due to a PPA termination agreement, and realized and unrealized derivative gains as part of our commercial hedging strategy.

Nine Months Ended September 30, 2023

Revenue

(in millions)

3376

Consolidated Revenue — Revenue increased $143 million, or 1%, for the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022, driven by:

  • $337 million at Renewables mainly driven by higher spot sales at higher prices and new projects placed into service; partially offset by the impact of the depreciation of the Colombian peso and unrealized derivative losses;

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

  • $29 million at Utilities mainly driven by higher fuel and purchase rider revenues, higher TDSIC rider and transmission revenues, and higher demand due to extreme heat in El Salvador; partially offset by lower retail sales volume as a result of lower demand due to unfavorable weather at Indiana and Ohio.

These favorable impacts were partially offset by a decrease of:

  • $314 million at Energy Infrastructure primarily driven by prior year favorable LNG transactions, lower CO2 purchases passed through due to lower production, the impact of the depreciation of the Argentine peso, lower generation, and the recognition of unrealized losses due to a PPA termination agreement; partially offset by higher revenues due to a PPA termination agreement, and realized and unrealized derivative gains resulting mainly from new derivatives as part of our commercial hedging strategy.

Operating Margin

(in millions)

4451

Consolidated Operating Margin — Operating margin increased $25 million, or 1%, for the nine months ended

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September 30, 2023, compared to the nine months ended September 30, 2022, driven by:

  • $71 million at Utilities mainly driven by the deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, a regulatory settlement in the prior year, an increase in transmission and TDSIC rider revenues, and higher demand due to extreme heat in El Salvador; partially offset by the impact of milder weather in Indiana and Ohio and higher fixed costs; and

  • $41 million at Renewables mainly driven by better hydrology, new projects placed into service, and higher wind availability, resulting in higher renewable energy generation; partially offset by unrealized derivative losses, and higher fixed costs due to an accelerated growth plan.

These favorable impacts were partially offset by a decrease of:

  • $91 million at Energy Infrastructure mainly driven by prior year favorable LNG transactions, higher cost of sales, lower thermal dispatch substituted with renewable sources, and a prior year one-time revenue recognition driven by a reduction in a project's expected completion costs; partially offset by unrealized gains resulting mainly from new derivatives as part of our commercial hedging strategy, lower outages and lower depreciation expense due to impairments recognized in the prior year.

See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-Q for additional discussion and analysis of operating results for each SBU.

Consolidated Results of Operations — Other

General and administrative expenses

General and administrative expenses increased $13 million, or 25%, to $64 million for the three months ended September 30, 2023, compared to $51 million for the three months ended September 30, 2022, primarily due to increased business development activity.

General and administrative expenses increased $42 million, or 28%, to $191 million for the nine months ended September 30, 2023 compared to $149 million for the nine months ended September 30, 2022, primarily due to increased business development activity and people costs.

Interest expense

Interest expense increased $50 million, or 18%, to $326 million for the three months ended September 30, 2023, compared to $276 million for the three months ended September 30, 2022. This increase is primarily due to new debt issued at the Renewables SBU and a higher weighted average interest rate and debt balance at the Parent Company; partially offset by higher capitalized interest at the Renewables SBU and the deferral of carrying costs at the Utilities SBU.

Interest expense increased $153 million, or 19%, to $966 million for the nine months ended September 30, 2023, compared to $813 million for the nine months ended September 30, 2022, primarily due to new debt issued at the Renewables 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 and Energy Infrastructure SBUs and the deferral of carrying costs at the Utilities SBU.

Interest capitalized during development and construction increased $97 million to $149 million for the three months ended September 30, 2023, compared to $52 million for the three months ended September 30, 2022, primarily due to more projects in development at the Renewables SBU and higher interest rates.

Interest capitalized during development and construction increased $254 million to $396 million for the nine months ended September 30, 2023, compared to $142 million for the nine months ended September 30, 2022, primarily due to more projects in development at the Renewables and Energy Infrastructure SBUs and higher interest rates.

Interest income

Interest income increased $44 million, or 44%, to $144 million for the three months ended September 30, 2023, compared to $100 million for the three months ended September 30, 2022, primarily due to higher average interest rates and short-term investments at the Energy Infrastructure and Renewables SBUs.

Interest income increased $128 million, or 47%, to $398 million for the nine months ended September 30, 2023, compared to $270 million for the nine months ended September 30, 2022, primarily due to higher average

44 | The AES Corporation | September 30, 2023 Form 10-Q

interest rates and short-term investments at the Energy Infrastructure and Renewables SBUs, partially offset by the prior year sales-type lease receivable adjustment at the Alamitos Energy Center.

Other income and expense

Other income increased $8 million to $12 million for the three months ended September 30, 2023, compared to $4 million for the three months ended September 30, 2022, with no material drivers.

Other income decreased $44 million, or 55%, to $36 million for the nine months ended September 30, 2023, compared to $80 million for the nine months ended September 30, 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 prior year insurance proceeds primarily associated with property damage at TermoAndes.

Other expense increased $2 million, or 20%, to $12 million for the three months ended September 30, 2023, compared to $10 million for the three months ended September 30, 2022, with no material drivers.

Other expense decreased $13 million, or 25%, to $38 million for the nine months ended September 30, 2023, compared to $51 million for the nine months ended September 30, 2022, primarily due to the prior year recognition of an allowance on a sales-type receivable at AES Gilbert due to a fire incident in April 2022.

See Note 14—Other Income and Expense included in Item 1.—Financial Statements of this Form 10-Q for further information.

Asset impairment expense

Asset impairment expense increased $108 million to $158 million for the three months ended September 30, 2023, compared to $50 million for the three months ended September 30, 2022. This increase was due to the $77 million and $59 million impairments at TEG and TEP in Mexico due to a reduction in expected cash flows after expiration of the current PPAs, partially offset by higher impairments in the prior year of Amman East and IPP4 in Jordan due to the delay in closing the sale transaction.

Asset impairment expense decreased $181 million, or 34%, to $352 million for the nine months ended September 30, 2023, compared to $533 million for the nine months ended September 30, 2022. This decrease was primarily due to the $468 million prior year impairment of Maritza’s coal-fired plant due to Bulgaria’s commitment to cease electricity generation using coal as a fuel-source beyond 2038, partially offset by the $137 million impairment associated with the commitment to accelerate the retirement of the Norgener coal-fired plant in Chile, and the $77 million and $59 million impairments at TEG and TEP as discussed above.

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

Foreign currency transaction gains (losses)

Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Argentina$(79)$(7)$(151)$(62)
Chile(24)11(69)—
Brazil(1)112(6)
Other43(1)8
Total (1)$(100)$8$(209)$(60)

(1)Includes gains of $15 million and gains of $33 million on foreign currency derivative contracts for the three months ended September 30, 2023 and 2022, respectively, and losses of $23 million and $16 million on foreign currency derivative contracts for the nine months ended September 30, 2023 and 2022, respectively.

The Company recognized net foreign currency transaction losses of $100 million for the three months ended September 30, 2023 primarily driven by the depreciation of the Argentine peso and by unrealized losses related to an intercompany loan denominated in the Colombian peso.

The Company recognized net foreign currency transaction losses of $209 million for the nine months ended September 30, 2023 primarily driven by the depreciation of the Argentine peso and unrealized losses related to an intercompany loan denominated in the Colombian peso; partially offset by unrealized gains on debt in Brazil.

The Company recognized net foreign currency transaction gains of $8 million for the three months ended September 30, 2022 primarily due to unrealized and realized derivative gains on foreign currency derivatives in South America due to the depreciating Colombian peso, partially offset by realized and unrealized losses due to the depreciating Argentine peso.

45 | The AES Corporation | September 30, 2023 Form 10-Q

The Company recognized net foreign currency transaction losses of $60 million for the nine months ended September 30, 2022 primarily due to the depreciating Argentine peso.

Income tax expense

Income tax expense decreased $36 million, or 25%, to $109 million for the three months ended September 30, 2023, compared to $145 million for the three months ended September 30, 2022. The Company’s effective tax rates were 26% and 24% for the three months ended September 30, 2023 and 2022, respectively. The current and prior year effective tax rates were benefited by inflationary and foreign currency impacts at certain Argentine businesses. Additionally, the current year effective tax rate was impacted by the recognition of valuation allowance against certain Argentine deferred tax assets. See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties of this Form 10-Q for further information on our exposure to foreign exchange rate risk related to the Argentine peso.

Income tax expense decreased $7 million, or 4%, to $179 million for the nine months ended September 30, 2023, compared to $186 million for the nine months ended September 30, 2022. The Company’s effective tax rate was 26% for both the nine months ended September 30, 2023 and 2022, respectively. The current and prior year effective tax rates were benefited by the aforementioned inflationary and foreign currency impacts. The current year effective tax rate was also impacted by the recognition of valuation allowance, while the prior year effective tax rate was impacted by favorable LNG transactions at the Energy Infrastructure SBU, offset by the impact of the asset impairment of the Maritza coal-fired plant. See Note 15—Asset Impairment Expense included in Item 1.—Financial Statements of this Form 10-Q for details of the Maritza asset impairment.

Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at rates different than the U.S. statutory rate of 21%. Furthermore, our foreign earnings may be subjected to incremental U.S. taxation under the GILTI rules. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate.

Net equity in losses of affiliates

Net equity in losses of affiliates decreased $12 million, or 46%, to $14 million for the three months ended September 30, 2023, compared to $26 million for the three months ended September 30, 2022. This decrease was primarily driven by lower losses from Fluence, mainly attributable to improved margins on a new product line.

Net equity in losses of affiliates decreased $11 million, or 20%, to $43 million for the nine months ended September 30, 2023, compared to $54 million for the nine months ended September 30, 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 costs. This decrease in losses was partially offset by lower earnings from sPower, mainly due to lower earnings from renewable projects that came online.

See Note 6—Investments in and Advances to Affiliates included in Item 1.—Financial Statements of this Form 10-Q for further information.

Net income attributable to noncontrolling interests and redeemable stock of subsidiaries

Net income attributable to noncontrolling interests and redeemable stock of subsidiaries increased $35 million to $60 million for the three months ended September 30, 2023, compared to $25 million for the three months ended September 30, 2022. This increase was primarily due to:

  • Lower allocation of losses to tax equity investors and increased costs associated with the growing business at the Renewables SBU; and

  • Lower impairments in Jordan at the Energy Infrastructure SBU.

These increases were partially offset by:

  • Lower earnings in Panama due to drier hydrology.

Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $6 million, or 5%, to $118 million for the nine months ended September 30, 2023, compared to $124 million for the nine months ended September 30, 2022. This decrease was primarily due to:

  • Increased costs associated with growing business at the Renewables SBU; and

46 | The AES Corporation | September 30, 2023 Form 10-Q

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

These decreases 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 attributable to The AES Corporation

Net income attributable to The AES Corporation decreased $190 million, or 45%, to $231 million for the three months ended September 30, 2023, compared to $421 million for the three months ended September 30, 2022. This decrease was primarily due to:

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

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

  • Lower earnings from the Energy Infrastructure SBU due to prior year favorable LNG transactions.

These decreases were partially offset by:

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

  • Higher earnings from the Renewables SBU due to favorable weather conditions and new businesses operating in our portfolio.

Net income attributable to The AES Corporation decreased $14 million, or 4%, to $343 million for the nine months ended September 30, 2023, compared to $357 million for the nine months ended September 30, 2022. This decrease was primarily due to:

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

  • Lower earnings from the Energy Infrastructure SBU due to prior year favorable LNG transactions, lower thermal dispatch, and higher cost of sales; and

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

These decreases were partially offset by:

  • Lower long-lived asset impairments 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 power purchase costs and a prior year charge resulting from a regulatory settlement; and

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

SBU Performance Analysis

Non-GAAP Measures

EBITDA, Adjusted EBITDA, Adjusted EBITDA with Tax Attributes, Adjusted PTC, and Adjusted EPS are non-GAAP supplemental measures that are used by management and external users of our condensed consolidated financial statements such as investors, industry analysts, and lenders.

During the first quarter of 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.

47 | The AES Corporation | September 30, 2023 Form 10-Q

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 excluding 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 expense allocated to tax equity investors.

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 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.

Three Months Ended September 30,Nine Months Ended September 30,
Reconciliation of Adjusted EBITDA and Adjusted EBITDA with Tax Attributes (in millions)2023202220232022
Net income$291$446$461$481
Income tax expense109145179186
Interest expense326276966813
Interest income(144)(100)(398)(270)
Depreciation and amortization286266836800
EBITDA$868$1,033$2,044$2,010
Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1)(183)(174)(508)(486)
Less: Income tax expense (benefit), interest expense (income) and depreciation and amortization from equity affiliates27369393
Interest income recognized under service concession arrangements18195458
Unrealized derivative and equity securities losses (gains)10(8)3—
Unrealized foreign currency losses97316123
Disposition/acquisition losses842136
Impairment losses14517318497
Loss on extinguishment of debt—117
Adjusted EBITDA (1)$990$931$2,187$2,238
Tax attributes allocated to tax equity investors186069109
Adjusted EBITDA with Tax Attributes (2)$1,008$991$2,256$2,347

48 | The AES Corporation | September 30, 2023 Form 10-Q

(1) The allocation of earnings 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 expense allocated to tax equity investors under the HLBV accounting method and recognized as Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries on the Condensed Consolidated Statements of Operations. All of the tax attributes are related to the Renewables SBU.

4689

4691

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 Corporate and Other as

49 | The AES Corporation | September 30, 2023 Form 10-Q

well as business development costs, interest expense and interest income, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings of affiliates.

The GAAP measure most comparable to Adjusted PTC is Income from continuing operations attributable to The AES Corporation. We believe that Adjusted PTC better reflects the underlying business performance of the Company and is a relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses 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, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure than Income from continuing operations attributable to The AES Corporation that better assists investors in determining which businesses have the greatest impact on the Company’s results.

Adjusted PTC should not be construed as an alternative to Income from continuing operations attributable to The AES Corporation, which is determined in accordance with GAAP.

Three Months Ended September 30,Nine Months Ended September 30,
Reconciliation of Adjusted PTC (in millions)2023202220232022
Income from continuing operations, net of tax, attributable to The AES Corporation$231$421$343$357
Income tax expense from continuing operations attributable to The AES Corporation101128136149
Pre-tax contribution332549479506
Unrealized derivative and equity securities losses (gains)9(8)3(2)
Unrealized foreign currency losses96316023
Disposition/acquisition losses842136
Impairment losses14517318497
Loss on extinguishment of debt34720
Adjusted PTC$593$569$988$1,080

7738

50 | The AES Corporation | September 30, 2023 Form 10-Q

7740

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, and the tax impact from the repatriation of sales proceeds, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; (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; and (g) 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.

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, the one-time impact of the 2017 U.S. tax law reform and subsequent period adjustments related to enactment effects, 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.

Three Months Ended September 30,Nine Months Ended September 30,
Reconciliation of Adjusted EPS2023202220232022
Diluted earnings per share from continuing operations$0.32$0.59$0.48$0.50
Unrealized derivative and equity securities losses (gains)0.01(0.01)—(1)—
Unrealized foreign currency losses0.14(2)—0.22(3)0.03(4)
Disposition/acquisition losses0.010.010.030.05(5)
Impairment losses0.21(6)0.02(7)0.45(8)0.70(9)
Loss on extinguishment of debt—0.010.010.03
Less: Net income tax expense (benefit)(0.09)(10)0.01(0.16)(11)(0.13)(12)
Adjusted EPS$0.60$0.63$1.03$1.18

(1)Amount primarily relates to unrealized derivative losses due to the termination of a PPA of $72 million, or $0.10 per share and unrealized derivative losses at AES Clean Energy of $20 million, or $0.03 per share, offset by unrealized derivative gains at the Energy Infrastructure SBU of $108 million, or $0.15 per share.

(2)Amount primarily relates to unrealized foreign currency losses mainly associated with the devaluation of long-term receivables denominated in Argentine pesos of $60 million, or $0.08 per share, unrealized foreign currency losses at AES Andes of $21 million, or $0.03 per share, and unrealized foreign currency losses on

51 | The AES Corporation | September 30, 2023 Form 10-Q

debt in Brazil of $10 million, or $0.01 per share.

(3)Amount primarily relates to unrealized foreign currency losses mainly associated with the devaluation of long-term receivables denominated in Argentine pesos of $109 million, or $0.15 per share, and unrealized foreign currency losses at AES Andes of $54 million, or $0.08 per share.

(4)Amount primarily relates to unrealized foreign currency losses mainly associated with the devaluation of long-term receivables denominated in Argentine pesos of $19 million, or $0.03 per share.

(5)Amount primarily relates to the recognition of an allowance on the AES Gilbert sales-type lease receivable as a cost of disposition of a business interest of $20 million, or $0.03 per share.

(6)Amount primarily relates to asset impairments at TEG and TEP of $76 million and $58 million, respectively, or $0.19 per share.

(7)Amount primarily relates to asset impairment at Jordan of $19 million, or $0.03 per share.

(8)Amount primarily relates to asset impairments 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, the GAF Projects at AES Renewable Holdings of $18 million, or $0.03 per share, and at Jordan of $16 million, or $0.02 per share.

(9)Amount primarily relates to asset impairment at Maritza of $468 million, or $0.66 per share, and at Jordan of $19 million, or $0.03 per share.

(10)Amount primarily relates to income tax benefits associated with the asset impairments at TEG and TEP of $34 million, or $0.05 per share and income tax benefits associated with unrealized foreign currency losses at AES Andes of $6 million, or $0.01 per share.

(11)Amount primarily relates to income tax benefits associated with the asset impairments at the Norgener coal fired plant in Chile of $35 million, or $0.05 per share and at TEG and TEP of $34 million, or $0.05 per share, income tax benefits associated with the recognition of unrealized losses due to the termination of a PPA of $18 million, or $0.02 per share, and income tax benefits associated with unrealized foreign currency losses at AES Andes of $14 million, or $0.02 per share.

(12)Amount primarily relates to income tax benefits associated with the impairment at Maritza of $73 million, or $0.10 per share, and at Jordan of $8 million, or $0.01 per share.

Renewables SBU

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

Three Months Ended September 30,Nine Months Ended September 30,
20232022$ Change% Change20232022$ Change% Change
Operating Margin$222$188$3418%$428$387$4111%
Adjusted EBITDA (1)2671957237%5574768117%
Adjusted EBITDA with Tax Attributes (1)2852553012%626585417%

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

Operating Margin for the three months ended September 30, 2023 increased $34 million driven primarily by better hydrology, new businesses operating in our portfolio, resulting in higher renewable energy generation, and the impact of the appreciation of the Colombian peso. This increase was partially offset by unrealized derivative losses, higher fixed costs due to an accelerated growth plan, and lower contracted energy sales.

Adjusted EBITDA for the three months ended September 30, 2023 increased $72 million primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, and depreciation expense.

Adjusted EBITDA with Tax Attributes for the three months ended September 30, 2023 increased $30 million primarily due to the increase in Adjusted EBITDA, partially offset by lower realized tax attributes driven by fewer projects being placed into service. During the three months ended September 30, 2023 and 2022, we realized $18 million and $60 million, respectively, from Tax Attributes earned by our U.S. renewables business.

Operating Margin for the nine months ended September 30, 2023 increased $41 million driven primarily by better hydrology, new businesses operating in our portfolio, and higher wind availability, resulting in higher renewable energy generation. This increase was partially offset by unrealized derivatives losses and higher fixed costs due to an accelerated growth plan.

Adjusted EBITDA for the nine months ended September 30, 2023 increased $81 million primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, and depreciation expense.

Adjusted EBITDA with Tax Attributes for the nine months ended September 30, 2023 increased $41 million primarily due to the increase in Adjusted EBITDA, partially offset by lower realized tax attributes driven by fewer projects being placed into service. During the nine months ended September 30, 2023 and 2022, we realized $69 million and $109 million, respectively, from Tax Attributes earned by our U.S. renewables business.

52 | The AES Corporation | September 30, 2023 Form 10-Q

Utilities SBU

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

Three Months Ended September 30,Nine Months Ended September 30,
20232022$ Change% Change20232022$ Change% Change
Operating Margin$160$79$81NM$351$280$7125%
Adjusted EBITDA (1)2161377958%5264567015%
Adjusted PTC (1) (2)1011586NM1601006060%

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

(2) Adjusted PTC remains a key metric used by management for analyzing our businesses in the utilities industry.

Operating Margin for the three months ended September 30, 2023 increased $81 million mainly driven by the deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval and a regulatory settlement in the prior year.

Adjusted EBITDA for the three months ended September 30, 2023 increased $79 million primarily due to the drivers above, adjusted for NCI.

Adjusted PTC for the three months ended September 30, 2023 increased $86 million due to the drivers above and the deferral of carrying costs associated with the ESP 4 approval in the current year.

Operating Margin for the nine months ended September 30, 2023 increased $71 million mainly driven by the deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, a regulatory settlement in the prior year, an increase in transmission and TDSIC rider revenues and higher demand due to extreme heat in El Salvador, partially offset by the impact of milder weather in Indiana and Ohio and higher fixed costs.

Adjusted EBITDA for the nine months ended September 30, 2023 increased $70 million primarily due to the drivers above, adjusted for NCI.

Adjusted PTC for the nine months ended September 30, 2023 increased $60 million due to the drivers above and the deferral of carrying costs associated with the ESP 4 approval in the current year, partially offset by higher interest expense due to new debt transactions and increases in defined benefit plan costs.

Energy Infrastructure SBU

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

Three Months Ended September 30,Nine Months Ended September 30,
20232022$ Change% Change20232022$ Change% Change
Operating Margin$504$588$(84)-14%$1,120$1,211$(91)-8%
Adjusted EBITDA (1)520620(100)-16%1,1651,353(188)-14%

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

Operating Margin for the three months ended September 30, 2023 decreased $84 million driven primarily by prior year favorable LNG transactions, lower contract energy sales due to lower prices, and higher cost of sales.

These losses were partially offset by higher revenues due to a PPA termination agreement and realized and unrealized gains resulting mainly from new derivatives as part of our commercial hedging strategy.

Adjusted EBITDA for the three months ended September 30, 2023 decreased $100 million primarily due to the drivers above, adjusted for NCI, unrealized derivative gains, and depreciation.

Operating Margin for the nine months ended September 30, 2023 decreased $91 million driven primarily by prior year favorable LNG transactions, higher cost of sales, lower thermal dispatch substituted with renewable sources, the recognition of unrealized losses due to a PPA termination agreement, and a prior year one-time revenue recognition driven by a reduction in a project's expected completion costs.

These losses were partially offset by unrealized gains resulting mainly from new 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 prior year.

Adjusted EBITDA for the nine months ended September 30, 2023 decreased $188 million primarily due to the

53 | The AES Corporation | September 30, 2023 Form 10-Q

drivers above, adjusted for NCI, unrealized derivatives gains, depreciation, higher realized foreign currency losses, and lower insurance recovery.

New Energy Technologies SBU

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

Three Months Ended September 30,Nine Months Ended September 30,
20232022$ Change% Change20232022$ Change% Change
Operating Margin$(2)$(2)$——%$(8)$(5)$(3)-60%
Adjusted EBITDA (1)(22)(27)5-19%(61)(88)2731%

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

Operating Margin for the three months ended September 30, 2023 remained flat, with no material drivers.

Adjusted EBITDA for the three months ended September 30, 2023 increased $5 million primarily driven by lower losses at Fluence, whose results are reported as Net equity in losses of affiliates on our Condensed Consolidated Statements of Operations, mainly attributable to improved margins on a new product line.

Operating Margin for the nine months ended September 30, 2023 decreased $3 million, with no material drivers.

Adjusted EBITDA for the nine months ended September 30, 2023 increased $27 million primarily due to improved margins on a new product line, the issuance of price increase change orders during the period, the settlement of contractual claims with a battery module vendor, and incremental 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 2023 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation, and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.—Business and Item 1A.—Risk Factors of our 2022 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 are circumventing antidumping and countervailing duty 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 tariffs that result from this investigation for a 24-month period. Since President Biden’s Proclamation, suppliers in Southeast Asia have imported cells and panels again to the U.S.

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 determination 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.

We have contracted and secured our expected requirements for solar panels for U.S. projects targeted to achieve commercial operations in 2023 and 2024.

54 | The AES Corporation | September 30, 2023 Form 10-Q

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

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 renewable projects.

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 hydroelectrics. 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 U.S. spring of 2024, with a 60% probability of extending into mid-2024. In Panama, the El Niño phenomenon typically means drier conditions than average, although local system impacts may vary due to other factors. Lower hydrology may result in increased energy purchases to cover contracted positions, or less energy available to sell in the spot market after fulfilling contract obligations. Consistent with expected El Niño impacts, local hydrological forecasts in Panama indicate below historical average inflows persisting through the beginning of the rainy season, 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 Brazil, El Niño generally means more rainfall in the southern region of the country, where system reservoir levels are currently high, mitigating El Niño risk. 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 dry conditions that are less severe than the broader system within periods of El Niño from June through September, which can result in additional energy available to sell in the spot market after fulfilling contract obligations. In the case of 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 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 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. Impacts may be material to our results of operations.

Macroeconomic and Political

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

Inflation Reduction Act and U.S. Renewable Energy Tax Credits — The Inflation Reduction Act (the “IRA”) was signed into law in the United States in 2022. The IRA includes provisions that are expected to benefit the U.S. clean energy industry, including increases, extensions 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.

55 | The AES Corporation | September 30, 2023 Form 10-Q

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 partners at the time of its creation, which for projects utilizing the investment tax credit is in the quarter the project begins commercial operation. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy. In 2022, we realized $267 million of earnings from Tax Attributes. In 2023, we expect an increase in Tax Attributes earned by our U.S. renewables business in line with the growth of that business. Based on construction schedules, a significant portion of these earnings will be realized in the fourth quarter.

The implementation of the IRA is expected to require substantial guidance from the U.S. Department of Treasury and other government agencies. While that guidance is 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 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 2023.

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. We will continue to monitor the issuance of draft legislation in Bulgaria, the Netherlands, as well as 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 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 recently. From July 1 to September 30, 2023, the yield on 10-year U.S. Treasury Notes rose from 3.84% to 4.57%.

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

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

Puerto Rico — As discussed in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties of the 2022 Form 10-K, our subsidiaries in Puerto Rico have long-term PPAs with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

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

56 | The AES Corporation | September 30, 2023 Form 10-Q

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 September 30, 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. The judge presiding over the case entered an order setting the confirmation schedule for PREPA’s third amended Plan of Adjustment as March 4, 2024 through March 15, 2024. The next hearing on PREPA’s disclosure statement is scheduled for November 14, 2023.

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. Additionally, AES Puerto Rico entered into a standstill and forbearance agreement with its noteholders because of the insufficiency of funds to meet the principal and interest obligations on its Series A Bond Loans due and payable on June 1, 2023, and going forward. AES Puerto Rico continues to work with PREPA and its noteholders on these liquidity challenges.

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 $63 million is recoverable as of September 30, 2023. However, it is reasonably possible that the estimate of undiscounted cash flows may change in the near term resulting in the need to write down our long-lived assets in Puerto Rico to fair value.

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 the 2022 Form 10-K.

AES Warrior Run PPA Termination — On March 23, 2023, the Company entered into an agreement to terminate the PPA for its 205 MW Warrior Run coal-fired power plant. The agreement was approved by the Maryland Public Service Commission in June and became effective on June 28, 2023. As of the effective date, Warrior Run will no longer sell its electricity to the offtaker, Potomac Edison, but will continue to provide capacity through May 31, 2024 in exchange for total proceeds of $357 million to be received in equal installments through January 2030. The previous expiration for the Warrior Run PPA was 2030. The Company is currently evaluating possible alternative uses for the facility once the PPA term expires on May 31, 2024. As of the filing date, management believes the carrying amount of our long-lived assets at Warrior Run of $200 million is recoverable as of September 30, 2023. However, it is reasonably possible that the estimate of undiscounted cash flows may no longer support the carrying value of our long-lived assets at Warrior Run in the near term resulting in the need to write down these assets to fair value.

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

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Comp to date. However, AES Maritza has been engaging 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”). The PPA Discussions are ongoing and the PPA continues to remain in place. However, there can be no assurance that, in the context of the 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 will involve 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 the outcome of the PPA Discussions or when those discussions will conclude. Nor can we predict how DG Comp might resolve its review if the PPA Discussions fail to result in an agreement concerning the agency’s review. AES Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurance that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of operations, and cash flows. As of September 30, 2023, the carrying value of our long-lived assets at Maritza is $333 million.

AES Ohio Distribution Rate Case — On December 14, 2022, the PUCO issued an order on AES Ohio’s application to increase its base rates for electric distribution service to address, in part, increased costs of materials and labor and substantial investments to improve distribution structures. Among other matters, the order establishes a revenue increase of $76 million for AES Ohio’s base rates for electric distribution service. This increase went into effect on September 1, 2023, following the approval of AES Ohio’s electric security plan on August 9, 2023.

AES Ohio Electric Security Plan — On September 26, 2022, AES Ohio filed its latest Electric Security Plan (ESP 4) with the PUCO, which is a comprehensive plan to enhance and upgrade its network and improve service reliability, provide greater safeguards for price stability, and continue investments in local economic development.

On April 10, 2023, AES Ohio entered into a Stipulation and Recommendation with the PUCO Staff and seventeen parties (the “Settlement”) with respect to AES Ohio’s ESP 4 application, and, on August 9, 2023, the PUCO approved the Settlement without modification. The Settlement provides for a three-year ESP without a rate stability charge, and, in addition to other items, provides for the following:

  • A Distribution Investment Rider for the term of the ESP allowing for the timely recovery of distribution investments by AES Ohio based on a 9.999% return on equity, subject to revenue caps;

  • The recovery of $66 million related to past expenditures by AES Ohio plus future carrying costs and the recovery of incremental vegetation management expenses up to certain annual limits during the term of ESP 4. During the third quarter of 2023, AES Ohio deferred $28 million of previously recognized purchased power costs and an additional $11 million of carrying costs related to this recovery; and

  • Funding of programs for assistance to low-income customers and for economic development.

In addition, with the approval of ESP 4, the new distribution rates, which were approved in the December 14, 2022 PUCO Order on AES Ohio's distribution rate case application, went into effect in September 2023.

AES Indiana Regulatory Rate Review — AES Indiana filed a petition with the IURC on June 28, 2023 for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in reliability and resiliency improvements, and enhancements to its customer systems. AES Indiana's proposed revenue increase was $134 million annually, or 8.9%. We expect to receive an order from the IURC by the end of the second quarter of 2024. Pending approval from the IURC, new rates are anticipated to go into effect in the summer of 2024.

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

58 | The AES Corporation | September 30, 2023 Form 10-Q

significantly impact our results of operations. For additional information, refer to Item 3.—Quantitative and Qualitative Disclosures About Market Risk.

Impairments

Long-lived Assets and Current Assets Held-for-Sale — During the nine months ended September 30, 2023, the Company recognized asset impairment expense of $352 million. See Note 15*—Asset Impairment Expense* included in Item 1.—Financial Statements of this Form 10-Q for further information. After recognizing this impairment expense, the carrying value of long-lived assets and current assets held-for-sale that were assessed for impairment totaled $667 million at September 30, 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.

Environmental

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals) and certain air emissions, such as SO2, NOx, particulate matter, mercury, and other hazardous air pollutants. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules and regulations; and Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses included in the 2022 Form 10-K.

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

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

On June 5, 2023, the EPA published a final Federal Implementation Plan to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and Maryland, and became effective during 2023. The FIP also includes enhancements to the revised Group 3 trading program, which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop

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emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels. It is too early to determine the impact of this final rule, but it may result in the need to purchase additional allowances or make operational adjustments.

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

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

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

Climate Change Regulation — On July 8, 2019, the EPA published the final Affordable Clean Energy (“ACE”) Rule which would have established CO2 emission rules for existing power plants under CAA Section 111(d) and would have replaced the EPA's 2015 Clean Power Plan Rule (“CPP”). However, on January 19, 2021, the D.C. Circuit vacated and remanded the ACE Rule. Subsequently, on June 30, 2022, the Supreme Court reversed the judgment of the D.C. Circuit Court and remanded for further proceedings consistent with its opinion holding that the “generation shifting” approach in the CPP exceeded the authority granted to the EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate, holding pending challenges to the ACE Rule in abeyance while the EPA developed a replacement rule. On May 23, 2023, EPA published a proposed rule that would vacate the ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing electric generating units (EGUs) and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operation to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s. We are still reviewing the proposed rule and the impact of the proposed rule, the results of further proceedings, and potential future greenhouse gas emissions regulations remain uncertain but could be material.

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

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include interpretations regarding implementation of the CCR Rule. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

On May 18, 2023, EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR. We are still reviewing the proposal and it is too early to determine the potential impact.

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

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

AES Southland's current plan is to comply with the SWRCB OTC Policy by shutting down and permanently retiring all existing generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach that utilize OTC by the compliance dates included in the OTC Policy. On August 15, 2023, the State Water Board considered the SACCWIS recommendation and adopted an amendment to the OTC Policy that established a final compliance date of December 31, 2026 for the Alamitos and Huntington Beach facilities. This extension is contingent upon the facilities participating in the Strategic Reserve established by AB 205.

The Company’s California subsidiaries have signed 20-year term PPAs with Southern California Edison for the new generating capacity, which have been approved by the California Public Utilities Commission. Construction of new generating capacity began in June 2017 at AES Huntington Beach and July 2017 at AES Alamitos. The new air-cooled combined cycle gas turbine generators and battery energy storage systems were constructed at the AES Alamitos and AES Huntington Beach generating stations. The new air-cooled combined cycle gas turbine generators at the AES Alamitos and AES Huntington Beach generating stations began commercial operation in early 2020 and there is currently no plan to replace the OTC generating units at the AES Redondo Beach generating station following the retirement. Certain OTC units were required to be retired in 2019 to provide interconnection capacity and/or emissions credits prior to startup of the new generating units, and the remaining AES OTC generating units in California will be shutdown and permanently retired by the OTC Policy compliance dates for these units. The SWRCB OTC Policy required the shutdown and permanent retirement of all remaining OTC generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach by December 31, 2020. The initial amendment extended the deadline for shutdown and retirement of AES Alamitos and AES Huntington Beach’s remaining OTC generating units to December 31, 2023 and extended the deadline for shutdown and retirement of AES Redondo Beach’s remaining OTC generating units to December 31, 2021 (the “AES Redondo Beach Extension”). In October 2020, the cities of Redondo Beach and Hermosa Beach filed a state court lawsuit challenging the AES Redondo Beach Extension. AES opposed the action and the court granted an order dismissing the matter. The case remains open subject to the resolution of counter claims between parties other than AES. Plaintiffs have initiated an additional challenge to the permit, and the outcome of that lawsuit is unclear. On March 16, 2021 the SACCWIS released their draft 2021 report to SWRCB. The report summarizes the State of California’s current electrical grid reliability needs and recommended a two-year extension to the compliance schedule for AES Redondo Beach to address system-wide grid reliability needs. The SWRCB public hearing regarding the final decision on the amendment of the OTC policy was held on October 19, 2021 and the Board voted in favor of extending the compliance date for AES Redondo Beach to December 31, 2023. The AES Redondo Beach NPDES permit has been administratively extended. On September 30, 2022, the Statewide Advisory Committee on Cooling Water Intake Structures approved a recommendation to the SWRCB to consider an extension of the OTC compliance dates for AES Huntington Beach, LLC and AES Alamitos, LLC, to December 31, 2026, in support of grid

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reliability. SWRCB released a draft OTC Policy amendment early in 2023 to be heard by the SWRCB on March 7, 2023. The final decision from SWRCB is expected during the second half of 2023.

Power plants are required to comply with the more stringent of state or federal requirements. At present, the California state requirements are more stringent and have earlier compliance dates than the federal EPA requirements, and are therefore applicable to the Company's California assets.

Challenges to the federal EPA's rule were filed and consolidated in the U.S. Court of Appeals for the Second Circuit, although implementation of the rule was not stayed while the challenges proceeded. On July 23, 2018, the U.S. Court of Appeals for the Second Circuit upheld the rule. The Second Circuit later denied a petition by environmental groups for rehearing. The Company anticipates that compliance with CWA Section 316(b) regulations and associated costs could have a material impact on our consolidated financial condition or results of operations.

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

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

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of the U.S. by steam-electric power plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash, and more stringent effluent limitations for flue gas desulfurization wastewater. AES Indiana Petersburg has installed a dry bottom ash handling system in response to the CCR rule and wastewater treatment systems in response to the NPDES permits in advance of the ELG compliance date. Other U.S. businesses already include dry handling of fly ash and bottom ash and do not generate flue gas desulfurization wastewater. Following the 2019 U.S. Court of Appeals vacatur and remand of portions of the 2015 ELG rule related to leachate and legacy water, on March 29, 2023, EPA published a proposed rule revising the 2020 Reconsideration Rule. The proposed rule would establish new best available technology economically achievable effluent limits for flue gas desulfurization wastewater, bottom ash treatment water, and combustion residual leachate. It is too early to determine whether any outcome of litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition, and results of operations.

Capital Resources and Liquidity

Overview

As of September 30, 2023, the Company had unrestricted cash and cash equivalents of $1.8 billion, of which $51 million was held at the Parent Company and qualified holding companies. The Company had $538 million in short-term investments, held primarily at subsidiaries, and restricted cash and debt service reserves of $570 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $21.6 billion and $5.6 billion, respectively. Of the $3.1 billion of our current non-recourse debt, $2.7 billion was presented as such because it is due in the next twelve months and $332 million relates to debt considered in default. Defaults at AES Puerto Rico are covenant and payment defaults, for which forbearance and standstill agreements have been signed. See Item 2.—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 September 30, 2023, the Company also had $775 million outstanding related to supplier financing arrangements, which are classified as Accrued and other

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liabilities.

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 $700 million in recourse debt which matures within the next twelve months, as well as amounts due under supplier financing arrangements, of which $607 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 $700 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 $27.5 billion of total gross debt outstanding as of September 30, 2023, approximately $7.2 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. 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.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction, or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment, or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. As of September 30, 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 $2.4 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 September 30, 2023, we had $248 million in letters of credit under bilateral agreements, $136 million in letters of credit outstanding provided under our unsecured credit facilities, and $39 million in letters of credit outstanding provided under our revolving credit facility. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the quarter ended September 30, 2023, the Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.

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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 September 30, 2023, the Company had approximately $118 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 September 30, 2024, 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 5*—Financing Receivables* in Item 1.—Financial Statements of this Form 10-Q and Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operation—Key Trends and Uncertainties—Macroeconomic and Political—Chile included in our 2022 Form 10-K for further information.

As of September 30, 2023, the Company had approximately $1.1 billion of loans receivable primarily related to a facility constructed under a build, operate, and transfer contract in Vietnam. 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 September 30, 2023, $105 million of the loan receivable balance was classified as Other current assets and $990 million was classified as Loan receivable on the Condensed Consolidated Balance Sheets. See Note 13*—Revenue* in Item 1.—Financial Statements of this Form 10-Q for further information.

Cash Sources and Uses

The primary sources of cash for the Company in the nine months ended September 30, 2023 were debt financings, cash flows from operating activities, purchases under supplier financing arrangements, and sales of short-term investments. The primary uses of cash in the nine months ended September 30, 2023 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 nine months ended September 30, 2022 were debt financings, cash flows from operating activities, and sales of short-term investments. The primary uses of cash in the nine months ended September 30, 2022 were repayments of debt, capital expenditures, purchases of short-term investments, acquisitions of noncontrolling interests, and purchases of emissions allowances.

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

Nine Months Ended September 30,
Cash Sources:20232022
Borrowings under the revolving credit facilities and commercial paper program$33,981$4,214
Net cash provided by operating activities2,3091,649
Issuance of non-recourse debt1,7843,554
Issuance of recourse debt1,400200
Purchases under supplier financing arrangements1,307299
Sale of short-term investments1,002654
Sales to noncontrolling interests371336
Contributions from noncontrolling interests63122
Other101132
Total Cash Sources$42,318$11,160
Cash Uses:
Repayments under the revolving credit facilities and commercial paper program$(32,168)$(2,782)
Capital expenditures(5,295)(2,711)
Repayments of non-recourse debt(1,262)(1,772)
Repayments of obligations under supplier financing arrangements(1,099)(234)
Purchase of short-term investments(764)(1,091)
Dividends paid on AES common stock(333)(316)
Acquisitions of business interests, net of cash and restricted cash acquired(311)(114)
Distributions to noncontrolling interests(173)(129)
Purchase of emissions allowances(161)(415)
Contributions and loans to equity affiliates(147)(202)
Acquisitions of noncontrolling interests(12)(541)
Other(345)(303)
Total Cash Uses$(42,070)$(10,610)
Net increase in Cash, Cash Equivalents, and Restricted Cash$248$550

Consolidated Cash Flows

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

Nine Months Ended September 30,
Cash flows provided by (used in):20232022$ Change
Operating activities$2,309$1,649$660
Investing activities(5,673)(3,825)(1,848)
Financing activities3,7402,863877

Operating Activities

Net cash provided by operating activities increased $660 million for the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022.

Operating Cash Flows

(in millions)

141

(1)The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Condensed Consolidated Statements of Cash Flows in Item 1—Financial Statements of this Form 10-Q.

(2)The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Condensed Consolidated Statements of Cash Flows in Item 1—Financial Statements of this Form 10-Q.

65 | The AES Corporation | September 30, 2023 Form 10-Q

  • Adjusted net income decreased $106 million primarily due to lower margins at our Energy Infrastructure SBU and an increase in interest expense; partially offset by higher margins at our Utilities and Renewables SBUs and an increase in interest income.

  • Working capital requirements decreased $766 million, primarily due to a decrease in accounts receivable resulting from higher collections, decreases in inventory and accounts payable due to lower inventory purchases at lower prices, and a decrease in derivative assets; partially offset by the receivables under the Warrior Run PPA termination agreement and an increase in lease incentives.

Investing Activities

Net cash used in investing activities increased $1.8 billion for the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022.

Investing Cash Flows

(in millions)

144

  • Acquisitions of business interests increased $197 million, primarily due to the acquisitions of Bellefield and Bolero Solar Park at AES Clean Energy Development and AES Andes, respectively, partially offset by the prior year acquisition of Agua Clara in the Dominican Republic.

  • Cash used for short-term investing activities decreased $675 million, primarily as a result of higher short-term investment sales in 2023 to fund the capital expenditures of our renewable projects.

  • Purchases of emissions allowances decreased $254 million, primarily in Bulgaria as a result of lower CO2 purchases due to lower production.

  • Capital expenditures increased $2.6 billion, discussed further below.

Capital Expenditures

(in millions)

913

66 | The AES Corporation | September 30, 2023 Form 10-Q

(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 increased $2.3 billion, primarily driven by an increase in U.S. renewable projects.

  • Maintenance expenditures increased $247 million, primarily due to higher transmission and distribution and renewable project investments at our Utilities SBU and increased expenditures for hydro and wind plants at our Renewables SBU.

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

Financing Activities

Net cash provided by financing activities increased $877 million for the nine months ended September 30, 2023, compared to the nine months ended September 30, 2022.

Financing Cash Flows

(in millions)

148

See Notes 7—Debt and 11—Equity in Item 1—Financial Statements of this Form 10-Q for more information regarding significant debt and equity transactions.

*•*The $1.2 billion impact from recourse debt is primarily due to the issuance of senior notes due in 2028 by the Parent Company, and the issuance of a bridge loan, fully guaranteed by the Parent Company, at AES Clean Energy.

  • The $840 million impact from non-recourse revolvers is primarily due to an increase in borrowings at our Renewables SBU to fund capital expenditures of renewable projects.

  • The $529 million impact from acquisitions of noncontrolling interests is mainly due to the acquisition of an additional 32% ownership interest in AES Andes in 2022.

*•*The $143 million impact from supplier financing arrangements is primarily due to higher net borrowings at the Renewables SBU, partially offset by higher net repayments at the Energy Infrastructure SBU.

  • The $1.3 billion impact from non-recourse debt transactions is mainly due to higher net repayments at Corporate and lower net borrowings at the Energy Infrastructure SBU.

  • The $459 million impact from the Parent Company revolver and commercial paper program is primarily due to higher net repayments in the current period.

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 facility and commercial paper program; and proceeds from asset sales. Cash requirements at the Parent Company level are primarily to

67 | The AES Corporation | September 30, 2023 Form 10-Q

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 facility 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):

September 30, 2023December 31, 2022
Consolidated cash and cash equivalents$1,765$1,374
Less: Cash and cash equivalents at subsidiaries(1,714)(1,350)
Parent Company and qualified holding companies’ cash and cash equivalents5124
Commitments under the Parent Company credit facility1,5001,500
Less: Letters of credit under the credit facility(39)(34)
Less: Borrowings under the credit facility—(325)
Less: Borrowings under the commercial paper program(604)—
Borrowings available under the Parent Company credit facility8571,141
Total Parent Company Liquidity$908$1,165

The Company utilizes its Parent Company credit facility and commercial paper program for short term cash needs to bridge the timing of distributions from its subsidiaries throughout the year.

The Parent Company paid dividends of $0.1659 per outstanding share to its common stockholders during the first, second, and third quarters of 2023 for dividends declared in December 2022, February 2023, and July 2023, respectively. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance that we will continue to pay dividends, or if continued, the amount of such dividends.

Recourse Debt

Our total recourse debt was $5.6 billion and $3.9 billion as of September 30, 2023 and December 31, 2022, respectively. See Note 7—Debt in Item 1.—Financial Statements of this Form 10-Q and Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of our 2022 Form 10-K for additional detail.

We believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future. This belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our revolving credit facility and commercial paper program. See Item 1A.—Risk Factors—The AES Corporation’s ability to make payments on its outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries of the Company’s 2022 Form 10-K for additional information.

Various debt instruments at the Parent Company level, including our revolving credit facility and commercial paper program, contain certain restrictive covenants. The covenants provide for, among other items, limitations on other indebtedness, liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions; restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements; maintenance of certain financial ratios; and financial and other reporting requirements. As of September 30, 2023, 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;

68 | The AES Corporation | September 30, 2023 Form 10-Q

  • 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 facility and outstanding debt securities at the Parent Company include events of default for certain bankruptcy-related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying Condensed Consolidated Balance Sheets amounts to $3.1 billion. The portion of current debt related to such defaults was $332 million at September 30, 2023, all of which was non-recourse debt related to four subsidiaries — AES Mexico Generation Holdings, AES Puerto Rico, AES Ilumina, and AES Jordan Solar. Defaults at AES Puerto Rico are covenant and payment defaults, for which forbearance and standstill agreements have been signed. 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. See Note 7—Debt in Item 1.—Financial Statements of this Form 10-Q for additional detail.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under the Parent Company’s debt agreements as of September 30, 2023, 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 facility as any business that contributed 20% or more of the Parent Company’s total cash distributions from businesses for the four most recently ended fiscal quarters. As of September 30, 2023, none of the defaults listed above, individually or in the aggregate, results in or is at risk of triggering a cross-default under the recourse debt of the Parent Company.

Critical Accounting Policies and Estimates

The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented.

The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies of our 2022 Form 10-K. The Company’s critical accounting estimates are described in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2022 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that these remain as critical accounting policies as of and for the nine months ended September 30, 2023.

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