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 2023 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 2023 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. For additional information regarding our business, see Item 1.—Business of our 2023 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 $81 million, from $291 million to $210 million. This decrease is the result of lower impairments and lower unrealized foreign currency losses in the current year, and higher contributions from renewables projects placed in service; partially offset by lower contributions from the Energy Infrastructure SBU.

Adjusted EBITDA, a non-GAAP measure, decreased $298 million, from $990 million to $692 million, driven by lower margins at the Energy Infrastructure SBU primarily due to the end of commercial operations at Warrior Run and prior year margin at the hedged merchant Southland facilities that are contracted primarily for capacity in the current year, and record-breaking drought conditions in South America at the Renewables SBU. This was partially offset by higher revenues from new projects at the Renewables SBU.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $160 million, from $1,008 million to $1,168 million primarily due to higher realized tax attributes driven by more renewables projects placed in service, partially offset by the drivers above.

38 | The AES Corporation | September 30, 2024 Form 10-Q

Compared with last year, third quarter diluted earnings per share from continuing operations increased $0.40, from $0.32 to $0.72. This increase is mainly driven by higher contributions from renewables projects placed in service in the current year, lower long-lived asset impairments in the current year, and prior year unrealized foreign currency losses at the Energy Infrastructure SBU. This was partially offset by lower earnings at the Energy Infrastructure SBU due to end of commercial operations at Warrior Run.

Adjusted EPS, a non-GAAP measure, increased $0.11 from $0.60 to $0.71, mainly driven by a lower adjusted tax rate and higher contributions from renewables projects placed in service in the current year, partially offset by lower contributions from the Energy Infrastructure SBU.

Compared with last year, net income for the nine months ended September 30, 2024 decreased $12 million, from $461 million to $449 million. This decrease is the result of higher interest expense and losses at commencement of sales-type leases at the Renewables SBU; partially offset by favorable contributions at the Utilities and New Energy Technologies SBUs, lower unrealized foreign currency losses in the current year, and higher contributions from renewables projects placed in service in the current year.

Adjusted EBITDA, a non-GAAP measure, decreased $208 million, from $2,187 million to $1,979 million, mainly driven by lower margins at the Energy Infrastructure SBU due to prior year margin at the hedged merchant Southland facilities that are contracted primarily for capacity in the current year and higher outages, and record-breaking drought conditions and outages in Colombia at the Renewables SBU; partially offset by higher contributions at the Utilities SBU, higher revenues from new projects at the Renewables SBU, and lower losses from affiliates at the New Energy Technologies SBU.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $618 million, from $2,256 million to $2,874 million, primarily due to higher realized tax attributes driven by more renewables projects placed in service, partially offset by the drivers above.

Compared with last year, diluted earnings per share from continuing operations for the nine months ended September 30, 2024 increased $1.10, from $0.48 to $1.58. This increase is mainly driven by higher contributions from renewables projects placed in service in the current year, prior year unrealized foreign currency losses at the Energy Infrastructure SBU, lower long-lived asset impairments in the current year, and lower income tax expense. This was partially offset by lower margins due to outages, the end of commercial operations at Warrior Run, higher interest expense, and losses at commencement of sales-type leases at the Renewables SBU.

Adjusted EPS, a non-GAAP measure, increased $0.57 from $1.03 to $1.60, mainly driven by a lower adjusted tax rate, higher contributions from renewables projects placed in service in the current year, and higher contributions from the Utilities SBU; partially offset by lower contributions from the Energy Infrastructure SBU.

39 | The AES Corporation | September 30, 2024 Form 10-Q



(1) Non-GAAP measure. See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition.
(2) GWh sold in 2023.

40 | The AES Corporation | September 30, 2024 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.

The Company’s PPA backlog, which consists of projects with signed contracts, but which are not yet operational, is 12.7 GW, including 4.0 GW under construction. Since the Company's second quarter 2024 earnings call in August 2024, the Company:

◦Signed or was awarded 1.3 GW of long-term PPAs for new renewables, for a total of 3.5 GW in year-to-date 2024; and

◦Completed the construction of 1.2 GW of solar, energy storage, wind and gas, and expects to add a total of 3.6 GW to its operating portfolio by year-end 2024.

Since the Company's second quarter 2024 earnings call in August 2024, the Company signed agreements with data center customers for an additional 900 MW of new load growth at AES Ohio, for a total of 2.1 GW in year-to-date 2024.
In 2023 and year-to-date 2024, the Company has announced or closed nearly three-quarters of its $3.5 billion asset sale proceeds target through 2027.

◦In September 2024, the Company agreed to sell a 30% indirect interest in AES Ohio to CDPQ for approximately $546 million.

◦On October 31, 2024, the Company closed the sale of its 47.3% equity interest in AES Brasil for approximately $630 million, including sale and hedge proceeds.

41 | The AES Corporation | September 30, 2024 Form 10-Q

Review of Consolidated Results of Operations (Unaudited)


	Three Months Ended September 30,								Nine Months Ended September 30,
(in millions, except per share amounts)	2024		2023		$ change		% change		2024		2023		$ change		% change
Revenue:
Renewables SBU	$	726	$	708	$	18	3	%	$	1,941	$	1,744	$	197	11	%
Utilities SBU	961		880		81		9	%	2,730		2,703		27		1	%
Energy Infrastructure SBU	1,623		1,861		(238)		-13	%	4,706		5,239		(533)		-10	%
New Energy Technologies SBU	1		—		1		NM		1		75		(74)		-99	%
Corporate and Other	33		29		4		14	%	106		96		10		10	%
Eliminations	(55)		(44)		(11)		-25	%	(168)		(157)		(11)		-7	%
Total Revenue	3,289		3,434		(145)		-4	%	9,316		9,700		(384)		-4	%
Operating Margin:
Renewables SBU	179		222		(43)		-19	%	323		428		(105)		-25	%
Utilities SBU	165		160		5		3	%	441		351		90		26	%
Energy Infrastructure SBU	355		504		(149)		-30	%	1,026		1,120		(94)		-8	%
New Energy Technologies SBU	(1)		(2)		1		-50	%	(5)		(8)		3		-38	%
Corporate and Other	47		58		(11)		-19	%	182		189		(7)		-4	%
Eliminations	(23)		(24)		1		4	%	(73)		(70)		(3)		-4	%
Total Operating Margin	722		918		(196)		-21	%	1,894		2,010		(116)		-6	%
General and administrative expenses	(57)		(64)		7		-11	%	(198)		(191)		(7)		4	%
Interest expense	(379)		(326)		(53)		16	%	(1,125)		(966)		(159)		16	%
Interest income	119		144		(25)		-17	%	312		398		(86)		-22	%
Loss on extinguishment of debt	(1)		—		(1)		NM		(11)		(1)		(10)		NM
Other expense	(31)		(12)		(19)		NM		(153)		(38)		(115)		NM
Other income	64		12		52		NM		120		36		84		NM
Gain (loss) on disposal and sale of business interests	(1)		—		(1)		NM		43		(4)		47		NM

Asset impairment expense	(79)		(158)		79		-50	%	(355)		(352)		(3)		1	%
Foreign currency transaction gains (losses)	(28)		(100)		72		-72	%	2		(209)		211		NM

Income tax expense	(103)		(109)		6		-6	%	(52)		(179)		127		-71	%
Net equity in losses of affiliates	(9)		(14)		5		-36	%	(21)		(43)		22		-51	%
INCOME FROM CONTINUING OPERATIONS	217		291		(74)		-25	%	456		461		(5)		-1	%

Gain from disposal of discontinued businesses	(7)		—		(7)		NM		(7)		—		(7)		NM
NET INCOME	210		291		(81)		-28	%	449		461		(12)		-3	%


Less: Net loss (income) attributable to noncontrolling interests and redeemable stock of subsidiaries	292		(60)		352		NM		670		(118)		788		NM
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	502	$	231	$	271	NM		$	1,119	$	343	$	776	NM
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	509	$	231	$	278	NM		$	1,126	$	343	$	783	NM
Loss from discontinued operations, net of tax	(7)		—		(7)		NM		(7)		—		(7)		NM
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	502	$	231	$	271	NM		$	1,119	$	343	$	776	NM
Net cash provided by operating activities	$	985	$	1,122	$	(137)	-12	%	$	1,664	$	2,309	$	(645)	-28	%

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 derivatives associated with the purchase of electricity or fuel.

Operating margin is defined as revenue less cost of sales.

42 | The AES Corporation | September 30, 2024 Form 10-Q

Consolidated Revenue and Operating Margin

Three Months Ended September 30, 2024

Revenue

(in millions)

1066

Consolidated Revenue — Revenue decreased $145 million, or 4%, for the three months ended September 30, 2024, compared to the three months ended September 30, 2023, driven by:

$238 million at Energy Infrastructure driven by the end of commercial operations at Warrior Run in the second quarter of 2024, lower regulated contract sales and prices, and the impact of the depreciation of the Argentine peso.

This unfavorable impact was partially offset by increases of:

$81 million at Utilities mainly driven by an increase in transmission and distribution revenues due to higher rates as a result of the 2024 Base Rate Order and higher demand due to favorable weather; and
$18 million at Renewables mainly driven by new projects in service, and the impact of better hydrology in Panama; partially offset by the impact of record-breaking drought conditions and outages in Colombia and the depreciation of the Brazilian real.

Operating Margin

(in millions)

1965

Consolidated Operating Margin — Operating margin decreased $196 million, or 21%, for the three months ended September 30, 2024, compared to the three months ended September 30, 2023, driven by:

$149 million at Energy Infrastructure mainly driven by the end of commercial operations at Warrior Run in the second quarter of 2024, higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, lower thermal dispatch, and higher outages; partially offset by favorable LNG transactions and lower fixed costs; and
$43 million at Renewables mainly driven by outages due to a flooding incident and record-breaking drought conditions in Colombia, as well as the depreciation of the Brazilian real; partially offset by higher generation due to better hydrology in Panama, new businesses operating in our portfolio, and unrealized derivative gains.

These unfavorable impacts were partially offset by an increase of $5 million at Utilities mainly driven by an increase in transmission and rider revenues, higher retail rates as a result of the 2024 Base Rate Order, and higher

43 | The AES Corporation | September 30, 2024 Form 10-Q

demand due to the impact of weather; partially offset by the prior year deferral of power purchase costs associated with the approval of ESP 4, and higher fixed costs.

Nine Months Ended September 30, 2024

Revenue

(in millions)

Consolidated Revenue — Revenue decreased $384 million, or 4%, for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023, driven by:

$533 million at Energy Infrastructure primarily driven by lower regulated contract sales and prices, lower CO2 purchases passed through due to lower production, the impact of the depreciation of the Argentine peso, higher revenues from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, and lower generation due to higher outages; partially offset by higher revenues due to a PPA termination agreement; and
$74 million at New Energy Technologies mainly driven by the sale of the Fallbrook project in March 2023.

These unfavorable impacts were partially offset by increases of:

$197 million at Renewables mainly driven by new projects in service, unrealized derivative gains, and the appreciation of the Colombian peso; partially offset by higher outages and record-breaking drought conditions in Colombia, and the depreciation of the Brazilian real; and
$27 million at Utilities mainly driven by an increase in transmission and distribution revenues due to higher rates, and higher demand due to favorable weather; partially offset by lower Fuel Adjustment Charge rider revenue.

Operating Margin

(in millions)

1042

Consolidated Operating Margin — Operating margin decreased $116 million, or 6%, for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023, driven by:

$105 million at Renewables driven by higher fixed costs, lower wind and solar availability, and record-breaking drought conditions and outage due to a flooding incident in Colombia; partially offset by unrealized derivative gains; and
$94 million at Energy Infrastructure mainly driven by higher outages, higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year,

44 | The AES Corporation | September 30, 2024 Form 10-Q

impact of the selldown of Amman East and IPP4 in Jordan, and lower thermal dispatch; partially offset by higher revenues due to a PPA termination agreement and lower fixed costs.

These unfavorable impacts were partially offset by an increase of $90 million at Utilities mainly driven by increases in transmission and rider revenues due to higher TDSIC, ECCRA and DIR, higher demand due to favorable weather, and higher retail rates as a result of the 2024 Base Rate Order; partially offset by the prior year deferral of power purchase costs associated with the approval of ESP 4, and higher fixed costs.

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 decreased $7 million, or 11%, to $57 million for the three months ended September 30, 2024, compared to $64 million for the three months ended September 30, 2023, primarily due to higher capitalization of business development costs, partially offset by higher people costs.

General and administrative expenses increased $7 million, or 4%, to $198 million for the nine months ended September 30, 2024, compared to $191 million for the nine months ended September 30, 2023, primarily due to increased business development activity and higher people costs.

Interest expense

Interest expense increased $53 million, or 16%, to $379 million for the three months ended September 30, 2024, compared to $326 million for the three months ended September 30, 2023. This increase is 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 an increase in capitalized interest.

Interest expense increased $159 million, or 16%, to $1,125 million for the nine months ended September 30, 2024, compared to $966 million for the nine months ended September 30, 2023. This increase is primarily due to the drivers above.

Interest capitalized during development and construction increased $15 million to $164 million for the three months ended September 30, 2024, compared to $149 million for the three months ended September 30, 2023, primarily due to more projects in development at the Renewables SBU, higher debt balances, and higher interest rates.

Interest capitalized during development and construction increased $95 million to $491 million for the nine months ended September 30, 2024, compared to $396 million for the nine months ended September 30, 2023, primarily due to the drivers above.

Interest income

Interest income decreased $25 million, or 17%, to $119 million for the three months ended September 30, 2024, compared to $144 million for the three months ended September 30, 2023, primarily due to lower short-term investments at the Energy Infrastructure and Renewables SBUs, partially offset by interest recognized on the Stabilization Fund receivables in Chile.

Interest income decreased $86 million, or 22%, to $312 million for the nine months ended September 30, 2024, compared to $398 million for the nine months ended September 30, 2023, primarily due to the drivers above.

Loss on extinguishment of debt

Loss on extinguishment of debt was $11 million for the nine months ended September 30, 2024 primarily due to a prepayment at AES Andes. See Note 8—Debt included in Item 1.—Financial Statements of this Form 10-Q for further information.

Other income and expense

Other income increased $52 million to $64 million for the three months ended September 30, 2024, compared to $12 million for the three months ended September 30, 2023, mainly due to gains on remeasurement of contingent consideration at AES Clean Energy and an indexation adjustment of Stabilization Fund receivables at AES Andes.

45 | The AES Corporation | September 30, 2024 Form 10-Q

Other income increased $84 million to $120 million for the nine months ended September 30, 2024, compared to $36 million for the nine months ended September 30, 2023, mainly due to gains on remeasurement of contingent consideration at AES Clean Energy, an indexation adjustment of Stabilization Fund receivables at AES Andes, a gain on commencement of a sales-type lease on land, and insurance proceeds primarily associated with property damage at AES Andes.

Other expense increased $19 million to $31 million for the three months ended September 30, 2024, compared to $12 million for the three months ended September 30, 2023, primarily driven by losses on remeasurement of contingent consideration at AES Clean Energy.

Other expense increased $115 million to $153 million for the nine months ended September 30, 2024, compared to $38 million for the nine months ended September 30, 2023, primarily driven by losses on commencement of sales-type leases at AES Renewable Holdings, legal expenses and other direct costs related to the troubled debt restructuring at Puerto Rico, and losses on remeasurement of contingent consideration at AES Clean Energy.

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

Gain (loss) on disposal and sale of business interests

Loss on disposal and sale of business interests was $1 million for the three months ended September 30, 2024, with no material drivers.

Gain on disposal and sale of business interests was $43 million for the nine months ended September 30, 2024, compared to a loss of $4 million for nine months ended September 30, 2023, driven by the gain on dilution of AES’ ownership interest in Uplight as a result of the AutoGrid acquisition, partially offset by the loss on the selldown of Amman East and IPP4 in Jordan, which is now accounted for as an equity method investment. See Note 7—Investments in and Advances to Affiliates and Note 18—Held-for-Sale and Dispositions for further information.

Asset impairment expense

Asset impairment expense decreased $79 million to $79 million for the three months ended September 30, 2024, compared to $158 million for the three months ended September 30, 2023. This decrease was due to prior year impairments of $77 million and $59 million at TEG and TEP, respectively, in Mexico due to a reduction in expected cash flows after expiration of the current PPAs, and a $14 million impairment at Amman East and IPP4 in Jordan due to the delay in closing the sale transaction. This was partially offset by current quarter impairments of $60 million and $11 million at AES Brasil and Mong Duong, respectively, due to subsequent impairment analyses after meeting held-for-sale criteria.

Asset impairment expense increased $3 million to $355 million for the nine months ended September 30, 2024, compared to $352 million for the nine months ended September 30, 2023. This increase was primarily due to current year impairments of $277 million and $54 million at AES Brasil and Mong Duong, respectively, after meeting held-for-sale criteria. This was partially offset by prior year impairments of $77 million and $59 million at TEG and TEP, respectively, $137 million associated with the commitment to accelerate the retirement of the Norgener coal-fired plant in Chile, $43 million at Amman East and IPP4 in Jordan due to the delay in closing the sale transaction, and $18 million at five project companies at AES Renewable Holdings associated with the buyout of tax equity partners.

See Note 16—Asset Impairment Expense included in Item 1.—Financial Statements of this Form 10-Q for further information.

46 | The AES Corporation | September 30, 2024 Form 10-Q

Foreign currency transaction gains (losses)


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2024		2023		2024		2023
Corporate	$	(17)	$	2	$	18	$	(7)
Brazil	1		(1)		1		12
Argentina	1		(79)		1		(151)
Chile	(13)		(24)		(17)		(69)






Other	—		2		(1)		6
Total (1)	$	(28)	$	(100)	$	2	$	(209)

(1)Includes losses of $15 million and gains of $15 million on foreign currency derivative contracts for the three months ended September 30, 2024 and 2023, respectively, and gains of $94 million and losses of $23 million on foreign currency derivative contracts for the nine months ended September 30, 2024 and 2023, respectively.

The Company recognized net foreign currency transaction losses of $28 million for the three months ended September 30, 2024, primarily driven by unrealized losses on swaps and options denominated in the Brazilian real and unrealized losses due to the depreciation of the Chilean peso.

The Company recognized net foreign currency transaction gains of $2 million for the nine months ended September 30, 2024, primarily driven by unrealized gains on swaps and options denominated in the Brazilian real; partially offset by unrealized losses due to the depreciation of the Chilean peso.

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 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.

Income tax expense

Income tax expense decreased $6 million, or 6%, to $103 million for the three months ended September 30, 2024, compared to $109 million for the three months ended September 30, 2023. The Company’s effective tax rates were 31% and 26% for the three months ended September 30, 2024 and 2023, respectively. This increase in the effective tax rate was impacted by tax expense resulting from allocations of losses to tax equity investors on renewables projects. Partially offsetting these impacts was the current quarter benefit associated with ITCs.

Income tax expense decreased $127 million, or 71%, to $52 million for the nine months ended September 30, 2024, compared to $179 million for the nine months ended September 30, 2023. The Company’s effective tax rates were 10% and 26% for the nine months ended September 30, 2024 and 2023, respectively. This decrease in the effective tax rate was largely due to the current year benefits associated with ITCs, the AES Brasil held-for-sale reclassification, and the restructuring of a foreign holding company. These drivers were partially offset by current year tax expense resulting from allocations of losses to tax equity investors on renewables projects. Further, the prior year effective tax rate was benefited by inflationary and foreign currency impacts at certain Argentine businesses, partially offset by the recognition of valuation allowance against certain Argentine deferred tax assets.

See Note 18—Held-for-Sale and Dispositions in Item 1.—Financial Statements of this Form 10-Q for further information on AES Brasil.

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 $5 million to $9 million for the three months ended September 30, 2024, compared to $14 million for the three months ended September 30, 2023. This decrease was primarily driven by higher earnings from sPower, primarily due to contributions from new projects that came online.

Net equity in losses of affiliates decreased $22 million to $21 million for the nine months ended September 30, 2024, compared to $43 million for the nine months ended September 30, 2023. This decrease was primarily driven by a decrease in losses from Fluence, mainly attributable to improved margins on a new product line, and higher earnings from sPower, primarily due to contributions from new projects that came online, partially offset by a

47 | The AES Corporation | September 30, 2024 Form 10-Q

decrease in earnings from Mesa La Paz, primarily due to the prior year termination of derivative positions due to a contract amendment.

See Note 7—Investments in and Advances to Affiliates included in Item 1.—Financial Statements of this Form 10-Q for further information.

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

Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries increased $352 million to a $292 million loss for the three months ended September 30, 2024, compared to income of $60 million for the three months ended September 30, 2023. This increase was primarily due to:

Higher allocation of losses to tax equity investors on renewables projects placed in service; and
Held-for-sale impairments at Brazil and Mong Duong.

These increases were partially offset by:

Selldowns of business interests resulting in larger shares of income attributable to minority shareholders at the Energy Infrastructure SBU; and
Better hydrology resulting in higher generation in Panama.

Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries increased $788 million to a $670 million loss for the nine months ended September 30, 2024, compared to income of $118 million for the nine months ended September 30, 2023. This increase was primarily due to:

Higher allocation of losses to tax equity investors on renewables projects placed in service; and
Held-for-sale impairments at Brazil and Mong Duong.

These increases were partially offset by:

Selldowns of business interests resulting in larger shares of income attributable to minority shareholders at the Energy Infrastructure SBU; and
Better hydrology resulting in higher generation in Panama.

Net income (loss) attributable to The AES Corporation

Net income attributable to The AES Corporation increased $271 million to $502 million for the three months ended September 30, 2024, compared to $231 million for the three months ended September 30, 2023. This increase was primarily due to:

Higher contributions from renewables projects placed in service in the current year;
Lower long-lived asset impairments in the current year; and
Unrealized foreign currency losses at the Energy Infrastructure SBU in the prior year.

These increases were partially offset by:

Lower contributions from the Energy Infrastructure SBU primarily due to the end of commercial operations at Warrior Run in the second quarter of 2024 and higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year;
Lower margins at the Renewables SBU driven by record-breaking drought conditions and partial outage due to a flooding incident in Colombia; and
Higher interest expense mainly from new debt at the Renewables and Utilities SBUs.

Net income attributable to The AES Corporation increased $776 million to $1,119 million for the nine months ended September 30, 2024, compared to $343 million for the nine months ended September 30, 2023. This increase was primarily due to:

Higher contributions from renewables projects placed in service in the current year;
Unrealized foreign currency losses at the Energy Infrastructure SBU in the prior year;
Lower long-lived asset impairments in the current year;
Higher revenues under a PPA termination agreement in the Energy Infrastructure SBU;

48 | The AES Corporation | September 30, 2024 Form 10-Q

Lower income tax expense; and
Higher earnings from the Utilities SBU.

These increases were partially offset by:

The impact of selldowns, higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, and higher outages at the Energy Infrastructure SBU;
Lower margins at the Renewables SBU driven by record-breaking drought conditions and partial outage due to a flooding incident in Colombia;
Losses on commencement of sales-type leases at AES Renewable Holdings; and
Higher interest expense and lower interest income in the current year.

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 2024, the Company updated the definitions of Adjusted EBITDA, Adjusted PTC, and Adjusted EPS add-back (a) unrealized gains or losses related to derivative transactions and equity securities to include financial assets and liabilities measured using the fair value option, and updated add-back (e) gains, losses, and costs due to the early retirement of debt to include troubled debt restructuring. We believe excluding these gains or losses better reflects the underlying business performance of the Company. The Company also removed the adjustment for net gains at Angamos, one of our businesses in the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. As this adjustment was specific to certain contract terminations that occurred in 2020, we believe removing this adjustment from our non-GAAP definitions provides simplification and clarity for our investors. There were no such impacts in 2023 or 2024 to date.

EBITDA, Adjusted EBITDA and Adjusted EBITDA with Tax Attributes

We define EBITDA as earnings before interest income and expense, taxes, depreciation, and amortization. We define Adjusted EBITDA as EBITDA adjusted for the impact of NCI and interest, taxes, depreciation, and amortization of our equity affiliates, adding back interest income recognized under service concession arrangements, and excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses pertaining to derivative transactions, equity securities, and financial assets and liabilities measured using the fair value option; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; and (e) gains, losses, and costs due to the early retirement of debt or troubled debt restructuring.

In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted EBITDA includes the other components of our Consolidated Statement of Operations, such as general and administrative expenses in Corporate and Other as well as business development costs, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings (losses) of affiliates.

We further define Adjusted EBITDA with Tax Attributes as Adjusted EBITDA, adding back the pre-tax effect of Production Tax Credits (“PTCs”), Investment Tax Credits (“ITCs”), and depreciation tax deductions allocated to tax equity investors, as well as the tax benefit recorded from tax credits retained or transferred to third parties.

The GAAP measure most comparable to EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes is Net income. We believe that EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes better reflect the underlying business performance of the Company. Adjusted EBITDA is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses pertaining to derivative transactions, equity securities, or financial assets and liabilities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or retire debt, and the variability of allocations of earnings to tax equity investors, which affect results in a given period or periods. In addition, each of these metrics represents the business performance of the Company before the application of statutory income tax rates and tax

49 | The AES Corporation | September 30, 2024 Form 10-Q

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)	2024		2023		2024		2023
Net income	$	210	$	291	$	449	$	461
Income tax expense	103		109		52		179
Interest expense	379		326		1,125		966
Interest income	(119)		(144)		(312)		(398)
Depreciation and amortization	306		286		926		836
EBITDA	$	879	$	868	$	2,240	$	2,044
Less: Income from discontinued operations	7		—		7		—
Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1)	(229)		(183)		(471)		(508)
Less: Income tax expense (benefit), interest expense (income) and depreciation and amortization from equity affiliates	30		27		91		93
Interest income recognized under service concession arrangements	16		18		49		54
Unrealized derivatives, equity securities, and financial assets and liabilities losses (gains)	(47)		10		(185)		3
Unrealized foreign currency losses	7		97		10		161
Disposition/acquisition losses (gains)	(11)		8		8		21
Impairment losses	39		145		179		318
Loss on extinguishment of debt and troubled debt restructuring	1		—		51		1

Adjusted EBITDA (1)	$	692	$	990	$	1,979	$	2,187
Tax attributes	476		18		895		69
Adjusted EBITDA with Tax Attributes (2)	$	1,168	$	1,008	$	2,874	$	2,256

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

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

50 | The AES Corporation | September 30, 2024 Form 10-Q

5439

5441

Adjusted PTC

We define Adjusted PTC as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses pertaining to derivative transactions, equity securities, and financial assets and liabilities measured using the fair value option; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits, and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; and (e) gains, losses, and costs due to the early retirement of debt or troubled debt restructuring. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities.

Adjusted PTC reflects the impact of NCI and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our Consolidated Statement of Operations, such as general and administrative expenses in Corporate and Other as well as business development costs, interest expense and interest income, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings (losses) of affiliates.

The GAAP measure most comparable to Adjusted PTC is Income from continuing operations attributable to The AES Corporation. We believe that Adjusted PTC better reflects the underlying business performance of the Company and is a relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses pertaining to

51 | The AES Corporation | September 30, 2024 Form 10-Q

derivative transactions, equity securities, or financial assets and liabilities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, and strategic decisions to dispose of or acquire business interests or retire debt, which affect results in a given period or periods. In addition, Adjusted PTC represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure 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)	2024		2023		2024		2023
Income from continuing operations, net of tax, attributable to The AES Corporation	$	509	$	231	$	1,126	$	343
Income tax expense (benefit) from continuing operations attributable to The AES Corporation	82		101		(4)		136
Pre-tax contribution	591		332		1,122		479
Unrealized derivatives, equity securities, and financial assets and liabilities losses (gains)	(47)		9		(185)		3
Unrealized foreign currency losses	7		96		10		160
Disposition/acquisition losses (gains)	(11)		8		8		21
Impairment losses	39		145		179		318
Loss on extinguishment of debt and troubled debt restructuring	3		3		57		7


Adjusted PTC	$	582	$	593	$	1,191	$	988

8377

52 | The AES Corporation | September 30, 2024 Form 10-Q

8379

Adjusted EPS

We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses pertaining to derivative transactions, equity securities, and financial assets and liabilities measured using the fair value option; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and the tax impact from the repatriation of sales proceeds, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; and (e) gains, losses, and costs due to the early retirement of debt or troubled debt restructuring.

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
Reconciliation of Adjusted EPS	2024			2023			2024			2023
Diluted earnings per share from continuing operations	$	0.72		$	0.32		$	1.58		$	0.48
Unrealized derivatives, equity securities, and financial assets and liabilities losses (gains)	(0.06)		(1)	0.01			(0.26)		(2)	—		(3)
Unrealized foreign currency losses	0.01			0.14		(4)	0.02			0.22		(5)
Disposition/acquisition losses (gains)	(0.02)			0.01			0.01		(6)	0.03
Impairment losses	0.05		(7)	0.21		(8)	0.25		(9)	0.45		(10)
Loss on extinguishment of debt and troubled debt restructuring	—			—			0.08		(11)	0.01



Less: Net income tax expense (benefit)	0.01			(0.09)		(12)	(0.08)		(13)	(0.16)		(14)
Adjusted EPS	$	0.71		$	0.60		$	1.60		$	1.03

(1)Amount primarily relates to net unrealized derivative gains at the Energy Infrastructure SBU of $50 million, or $0.07 per share, and unrealized gains on commodity derivatives at AES Clean Energy of $17 million, or $0.02 per share, partially offset by unrealized losses on foreign currency derivatives at Corporate of $17 million, or $0.02 per share.

(2)Amount primarily relates to net unrealized derivative gains at the Energy Infrastructure SBU of $109 million, or $0.15 per share, unrealized gains on commodity derivatives at AES Clean Energy of $33 million, or $0.05 per share, unrealized gains on cross currency swaps in Brazil of $28 million, or $0.04 per share, and unrealized gains on foreign currency derivatives at Corporate of $20 million, or $0.03 per share.

(3)Amount primarily relates to recognition of 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,

53 | The AES Corporation | September 30, 2024 Form 10-Q

or $0.15 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 $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 debt in Brazil of $10 million, or $0.01 per share.

(5)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.

(6)Amount primarily relates to day-one losses at commencement of sales-type leases at AES Renewable Holdings of $63 million, or $0.09 per share, and the loss on partial sale of our ownership interest in Amman East and IPP4 in Jordan of $10 million, or $0.01 per share, partially offset by a gain on dilution of ownership in Uplight due to its acquisition of AutoGrid of $52 million, or $0.07 per share.

(7)Amount primarily relates to impairment at Brazil of $29 million, or $0.04 per share, and impairment at Mong Duong of $6 million, or $0.01 per share.

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

(9)Amount primarily relates to impairment at Brazil of $131 million, or $0.18 per share, and impairment at Mong Duong of $28 million, or $0.04 per share.

(10)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.

(11)Amount primarily relates to losses incurred at AES Andes due to early retirement of debt $29 million, or $0.04 per share, and costs incurred due to troubled debt restructuring at Puerto Rico of $20 million, or $0.03 per share.

(12)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.

(13)Amount primarily relates to income tax benefits associated with the tax over book investment basis differences related to the AES Brasil held-for-sale classification of $59 million, or $0.08 per share.

(14)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.

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,
	2024		2023		$ Change		% Change		2024		2023		$ Change		% Change
Operating Margin	$	179	$	222	$	(43)	-19	%	$	323	$	428	$	(105)	-25	%

Adjusted EBITDA (1)	199		267		(68)		-25	%	443		557		(114)		-20	%
Adjusted EBITDA with Tax Attributes (1)	674		285		389		NM		1,321		626		695		NM

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

Operating Margin for the three months ended September 30, 2024 decreased $43 million. This decrease was primarily driven by record-breaking drought conditions in Colombia. Additionally, a partial outage in Colombia during July 2024, which resulted from a flooding incident at the Chivor plant in the prior month, drier hydrology in Brazil and the depreciation of the Brazilian real further impacted operating margin. These adverse effects were partially offset by higher margins due to better hydrology in Panama, new businesses operating in our portfolio, higher contracted energy sales, and unrealized derivative gains.

Adjusted EBITDA for the three months ended September 30, 2024 decreased $68 million, primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, and depreciation.

Adjusted EBITDA with Tax Attributes for the three months ended September 30, 2024 increased $389 million, primarily due to higher realized tax attributes driven by more renewables projects placed in service, partially offset by the decrease in Adjusted EBITDA. During the three months ended September 30, 2024 and 2023, we realized $475 million and $18 million, respectively, from tax attributes earned by our U.S. renewables business.

Operating Margin for the nine months ended September 30, 2024 decreased $105 million, driven primarily by higher fixed costs due to an accelerated growth plan, record-breaking drought conditions in Colombia, reduced wind and solar availability alongside drier hydrological conditions in Brazil, and higher outages at Colombia due to a flooding incident at the Chivor plant which occurred in June 2024, partially offset by higher margin from new businesses, higher contracted energy sales and unrealized derivatives gains.

Adjusted EBITDA for the nine months ended September 30, 2024 decreased $114 million, primarily due to the drivers mentioned above, adjusted for NCI, and depreciation.

Adjusted EBITDA with Tax Attributes for the nine months ended September 30, 2024 increased $695 million, primarily due to higher realized tax attributes driven by more renewables projects placed in service, partially offset by the decrease in Adjusted EBITDA. During the nine months ended September 30, 2024 and 2023, we realized $878 million and $69 million, respectively, from tax attributes earned by our U.S. renewables business.

54 | The AES Corporation | September 30, 2024 Form 10-Q

Utilities SBU

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


	Three Months Ended September 30,								Nine Months Ended September 30,
	2024		2023		$ Change		% Change		2024		2023		$ Change		% Change
Operating Margin	$	165	$	160	$	5	3	%	$	441	$	351	$	90	26	%

Adjusted EBITDA (1)	223		216		7		3	%	619		526		93		18	%
Adjusted EBITDA with Tax Attributes (1)	224		216		8		4	%	636		526		110		21	%
Adjusted PTC (1) (2)	73		101		(28)		-28	%	197		160		37		23	%

(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, 2024 increased $5 million, driven primarily by the increase in transmission and rider revenues due to higher ECCRA and DIR, higher retail rates as a result of the 2024 Base Rate Order, and higher demand due to the impact of weather. These increases are partially offset by the prior year deferral of power purchase costs associated with the approval of ESP 4, and higher fixed costs.

Adjusted EBITDA for the three months ended September 30, 2024 increased $7 million, primarily due to the drivers above, adjusted for NCI and depreciation.

Adjusted EBITDA with Tax Attributes increased $8 million, mainly driven by the drivers above.

Adjusted PTC for the three months ended September 30, 2024 decreased $28 million due to the drivers above, offset by higher depreciation expense and higher interest expense, primarily due to increased borrowings at IPALCO and the prior year deferral of carrying costs associated with the approval of ESP 4.

Operating Margin for the nine months ended September 30, 2024 increased $90 million, mainly driven by an increase in transmission and rider revenues due to higher TDSIC, ECCRA and DIR; higher demand due to the impact of weather and higher retail rates as a result of the 2024 Base Rate Order. These increases are partially offset by the prior year deferral of power purchase costs associated with the approval of ESP 4, and higher fixed costs.

Adjusted EBITDA for the nine months ended September 30, 2024 increased $93 million, primarily due to the drivers above, adjusted for NCI and depreciation.

Adjusted EBITDA with Tax Attributes increased $110 million due to the drivers above, as well as $17 million of realized tax attributes related to the Hardy Hills solar project in the current year.

Adjusted PTC for the nine months ended September 30, 2024 increased $37 million due to the drivers above, partially offset by higher depreciation expense and higher interest expense, primarily due to increased borrowings at IPALCO and the prior year deferral of carrying costs associated with the approval of ESP 4.

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,
	2024		2023		$ Change		% Change		2024		2023		$ Change		% Change
Operating Margin	$	355	$	504	$	(149)	-30	%	$	1,026	$	1,120	$	(94)	-8	%

Adjusted EBITDA (1)	299		520		(221)		-43	%	969		1,165		(196)		-17	%

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

Operating Margin for the three months ended September 30, 2024 decreased $149 million, driven primarily by lower revenues due to end of commercial operations of Warrior Run, higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, lower thermal dispatch substituted with renewable sources, and impact of the selldown of Amman East and IPP4 in Jordan. These losses were partially offset by favorable LNG transactions.

Adjusted EBITDA for the three months ended September 30, 2024 decreased $221 million, primarily due to the drivers above adjusted for NCI and unrealized derivatives.

55 | The AES Corporation | September 30, 2024 Form 10-Q

Operating Margin for the nine months ended September 30, 2024 decreased $94 million, driven by higher energy margin from our hedged merchant Southland facilities in the prior year that are contracted primarily for capacity in the current year, higher outages, impact of the selldown of Amman East and IPP4 in Jordan, and lower thermal dispatch substituted by renewable sources. These losses were partially offset by higher revenues due to a PPA termination agreement and lower fixed costs.

Adjusted EBITDA for the nine months ended September 30, 2024 decreased $196 million, primarily due to the drivers above, adjusted for NCI and unrealized derivatives.

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,
	2024		2023		$ Change		% Change		2024		2023		$ Change		% Change
Operating Margin	$	(1)	$	(2)	$	1	-50	%	$	(5)	$	(8)	$	3	38	%

Adjusted EBITDA (1)	(7)		(22)		15		-68	%	(38)		(61)		23		38	%

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

Operating Margin for the three months ended September 30, 2024 increased $1 million, with no material drivers.

Adjusted EBITDA for the three months ended September 30, 2024 increased $15 million, primarily due to a reduction in losses at Fluence as a result of higher margins on a new product line.

Operating Margin for the nine months ended September 30, 2024 increased $3 million, with no material drivers.

Adjusted EBITDA for the nine months ended September 30, 2024 increased $23 million, primarily due to a reduction in losses at Fluence as a result of higher margins on a new product line.

Key Trends and Uncertainties

During 2024 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation, and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.—Business and Item 1A.—Risk Factors of our 2023 Form 10-K.

Operational

Trade Restrictions and Supply Chain — On April 1, 2022, the U.S. Department of Commerce (“Commerce”) initiated an investigation into whether imports into the U.S. of solar cells and panels imported from Cambodia, Malaysia, Thailand, and Vietnam (“Southeast Asia”) are circumventing antidumping and countervailing duty (“AD/CVD”) orders on solar cells and panels from China. This investigation resulted in significant systemic disruptions to the import of solar cells and panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any circumvention duties on imported solar cells and panels from Southeast Asia that result from this investigation for a 24-month period ending June 6, 2024. Suppliers resumed importing cells and panels from Southeast Asia into the U.S. pursuant to a Commerce certification regime implementing the Proclamation.

On December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four Southeast Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to several 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 comprising the cells and panels were manufactured outside of China or if no more than two out of six specifically identified panel components were produced in China. On August 23, 2023, Commerce published its final determinations and affirmed its preliminary findings in most respects. Commerce found that three of the specific companies it investigated were not circumventing. Several parties have challenged Commerce’s circumvention final

56 | The AES Corporation | September 30, 2024 Form 10-Q

determinations before the U.S. Court of International Trade (“CIT”), arguing that the determinations were not supported by substantial evidence or otherwise rendered in accordance with governing law.

On December 29, 2023, Auxin Solar and Concept Clean Energy filed a lawsuit before the CIT, challenging certain aspects of the final rule promulgated by Commerce to implement the Proclamation. The lawsuit specifically challenges Commerce’s decisions not to suspend the final disposition of certain entries of imported solar cells and panels from Southeast Asia made prior to June 6, 2024, and not to collect AD/CVD deposits with respect to those entries. Certain U.S. developers, associations, and foreign solar producers have intervened in the case to support Commerce’s final rule. The CIT denied motions to dismiss filed by the U.S. Department of Justice, and the defendant-intervenors, and on July 22, 2024, plaintiffs filed their opening brief on the merits.

On April 24, 2024, new Commerce regulations with respect to the administration of AD/CVD cases went into effect, including regulations pertaining to transnational subsidization and particular market situations. On the same day, several companies filed a petition requesting that Commerce initiate an investigation into whether new AD/CVD duties should be imposed on cells and modules imported from Thailand, Cambodia, Malaysia, and Vietnam. These petitions cover exports of cells and panels from Southeast Asia that are not otherwise subject to the Commerce circumvention determinations. On May 14, 2024, Commerce initiated new AD/CVD investigations with respect to all four countries, and the U.S. International Trade Commission (the “ITC”) preliminarily voted to continue its investigations on June 7, 2024. On October 4, 2024, Commerce published its CVD preliminary determinations, establishing CVD cash deposit requirements, which may be applied retroactively with respect to Thailand and Vietnam. Commerce is scheduled to announce its AD preliminary determinations in these investigations in late November of 2024. The ITC will conduct its final injury investigation with respect to these exports from Southeast Asia in the first half of 2025. If the Commerce and ITC investigations result in Commerce issuing AD/CVD orders, the orders are likely to be imposed in the second or third quarter of 2025.

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

Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China, at any point in the supply chain, and may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While this has impacted the U.S. market, AES has managed this issue without significant impact to our projects. Further disruptions may impact our suppliers’ ability or 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 new Commerce investigations or any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the solar panel supply chain and their effect on AES’ U.S. solar project development and construction activities remain uncertain. AES will continue to monitor developments and take prudent steps towards maintaining a robust supply chain for our renewables projects. To that end, we have contracted and secured all of the necessary solar panels for our projects in our backlog expected to come online through 2026. We have all the 2024 panels and we expect to have the majority of the 2025 and 2026 panels in the United States by November.

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

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

According to the National Oceanic and Atmospheric Administration ("NOAA"), neutral conditions are currently observed. La Niña is emerging and expected to continue to emerge through November (60% chance) and is expected to persist through January-March 2025.

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In Panama, La Niña phenomenon in contrast to El Niño typically results in wetter conditions than average, although local system impacts may vary due to other factors. Higher hydrology may result in energy surpluses after covering the contracted hydro positions, available to be sold in the spot market after fulfilling contract obligations.

In Colombia, La Niña is typically characterized by more rainfall, possibly leading to a decrease in spot prices. However, during La Niña, impacts vary and the basin where Chivor is located may experience drier conditions than the system. Inflows at our Chivor hydroelectric plant have been below historical averages in the third quarter of 2024. Although conditions are currently expected to return to normal levels in the fourth quarter, should dry conditions persist, Chivor may be exposed to higher spot prices.

In Brazil, La Niña results in more rainfall in the north, drier conditions in the south, and milder temperatures in the central region. Current system reservoir levels remain high, supporting lower spot market prices. However, inflows lower than expected may cause spot and future prices to rise. Lower prices limit external thermal generation which, if dispatched, could impact demand for the AES hydro generation.

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

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

Macroeconomic and Political

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

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

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

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

In 2023, we realized $611 million of earnings from tax attributes, comprised of $593 million from the Renewables SBU and $18 million from the Utilities SBU. In 2024, we expect an increase in tax attributes earned by our U.S. renewables business in line with the growth in that business. Based on construction schedules, a significant portion of these earnings will be realized in the fourth quarter. For the nine months ended September 30, 2024, we recognized $895 million in tax attributes.

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

Argentina — President Javier Milei was elected on December 10, 2023 and has instituted a series of reforms impacting the power sector.

On July 8, 2024, the Argentine government enacted Law 27,742 or Ley Bases, translated in English as Law of Bases and Starting Points for the Freedom of the Argentine People. Ley Bases declares a public emergency in

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administrative, economic, financial, and energy matters for a term of one year, grants delegated powers to the President, and contains a broad reform of the State in order to deregulate the economy, including measures such as labor reform, the implementation of the Incentive Regime for Large Investments, and the modification of several non-income tax measures. The law also opens avenues for privatization of state-owned energy companies.

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

These changes may have a profound impact on the sector, influencing our operations and financial results. It is not yet possible to predict the impact of these regulations in our consolidated results of operations, cash flows, and financial condition.

Global Tax — The macroeconomic and political environments in the U.S. and in some countries where our subsidiaries conduct business have changed in recent years. This could result in significant impacts to future tax law. In the U.S., the IRA includes a 15% corporate alternative minimum tax (CAMT) based on adjusted financial statement income. In September 2024, the IRS released proposed regulations on the 15% CAMT. The Company is currently evaluating the potential impacts of these regulations.

During 2023, the Netherlands, Bulgaria, and Vietnam adopted legislation to implement Pillar 2 effective as of January 1, 2024. We will continue to monitor the issuance of draft legislation in other non-EU countries where the Company operates that are considering Pillar 2 amendments and new interpretive guidance. The impact to the Company during 2024 is not expected to 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 that are denominated in a currency other than the U.S. dollar are indexed to inflation, in general, our U.S.-based generation contracts are not indexed to inflation. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may also increase the costs of some of our development projects that could negatively impact their competitiveness. Our utility businesses do allow for recovering of operations and maintenance costs through the regulatory process, which may have timing impacts on recovery.

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

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

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

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 2023 Form 10-K, our subsidiaries in Puerto Rico have long-term PPAs with state-owned PREPA, which has been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico. Despite the Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

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

PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017.

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As a result of the bankruptcy filing, AES Ilumina’s non-recourse debt of $23 million continues to be in technical default and is classified as current as of September 30, 2024.

In 2022, a mediation commenced to resolve the PREPA Title III case. The confirmation trial ended in March 2024 and the decision is pending.

Considering the information available as of the date hereof, management believes the carrying amount of our long-lived assets in Puerto Rico of $384 million is recoverable as of September 30, 2024.

Decarbonization Initiatives

Our strategy involves shifting towards clean energy platforms, including renewable energy, energy storage, LNG, and modernized grids. It is designed to position us for continued growth while reducing our carbon intensity and to be in support of our mission of accelerating the future of energy, together. We have made significant progress on our exit of coal generation, and 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, Bulgaria, and offtakers in recent years, with the intention of reducing GHG emissions generated by the energy industry. In parallel, the shift towards renewables has caused certain customers to migrate to other low-carbon energy solutions and this trend may continue.

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

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 2023 Form 10-K.

Regulatory

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

We do not believe termination of the PPA is justified. Nevertheless, the PPA Discussions involved a range of potential outcomes, including but not limited to the termination of the PPA and payment of some level of compensation to AES Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict whether and when the PPA Discussions might resume or the outcome of any such discussions. Nor can we predict how DG Comp might resolve its review if the PPA Discussions do not resume or if any such discussions fail to result in an agreement concerning the agency's review. AES Maritza believes that its PPA is legal and in compliance with all applicable laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or otherwise. However, there can be no assurance that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of operations, and cash flows. As of September 30, 2024, the carrying value of our long-lived assets at Maritza is $336 million.

AES Indiana DSM Plan Petition — On May 31, 2024, AES Indiana filed a petition with the IURC asking for approval of a two year Demand-Side Management (DSM) plan for the 2025-2026 program years. The petition includes requested cost recovery of programs as well as performance incentives, depending on the level of success of the programs consistent with prior DSM plans. On October 1, 2024, AES Indiana and the Office of Utility Consumer Counselor (“OUCC”) filed settlement testimony with the IURC in support of approval of a Stipulation and Settlement Agreement reached between the settling parties (AES Indiana, OUCC, and Citizens Action Coalition). An evidentiary hearing on this matter was held by the IURC on October 22, 2024. We expect the IURC to issue an order on this proceeding by the end of 2024.

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AES Indiana Regulatory Rate Review — On April 17, 2024, the IURC issued an order (the “2024 Rate Order”) approving the Stipulation and Settlement Agreement that AES Indiana entered into on November 22, 2023, with the OUCC and the other intervening parties in AES Indiana’s base rate case filing. Among other matters and consistent with the Stipulation and Settlement Agreement, the 2024 Rate Order approves an increase in AES Indiana's total annual operating revenue of $71 million for AES Indiana’s electric service and provides a return on common equity of 9.9% and cost of long-term debt of 4.90% on a rate base of approximately $3.5 billion. Updated customer rates and charges became effective on May 9, 2024.

AES Indiana Petersburg Repowering — On March 11, 2024, AES Indiana filed for approval of a CPCN seeking for IURC approval to repower Petersburg Generation Units 3 & 4 from coal to natural gas and to recover costs through future rates. The conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026 and the conversion of Unit 4 is expected to begin in June 2026 and be completed by December 2026. An evidentiary hearing on this matter was held by the IURC on August 6, 2024, and we expect the IURC to issue an order on this proceeding during the fourth quarter of 2024.

AES Ohio Smart Grid Phase 2 Filing — In February 2024, AES Ohio filed a Smart Grid Phase 2 with the PUCO proposing to invest approximately $683 million in capital projects over a 10-year period following Smart Grid Phase 1, which ends June 2025. On September 13, 2024, AES Ohio reached a settlement with the PUCO Staff and other parties to resolve the pending Smart Grid Phase 2 Application. The Settlement will provide for a four-year plan to invest $241 million of capital and $19 million of operations and maintenance expense related to grid modernization, support of Distributed Energy Resources and Economic Development and an enhanced Telecommunications network. These costs will be recovered through the existing Investment Infrastructure Rider.

If approved, AES Ohio will implement a comprehensive grid modernization project that will deliver benefits to customers, society as a whole and to AES Ohio. An evidentiary hearing was held on October 29, 2024, and we expect an order from PUCO by the second quarter of 2025, prior to the end of Smart Grid Phase 1.

AES Ohio Distribution Rate Case — On October 30, 2024, AES Ohio filed a Pre-filing Notice of Intent to file an application to increase rates for distribution service. The Distribution Rate Case Application will be filed on November 29, 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 significantly impact our results of operations. For additional information, refer to Item 3.—Quantitative and Qualitative Disclosures About Market Risk.

Impairments and Realizability

Long-lived Assets and Current Assets Held-for-Sale — During the nine months ended September 30, 2024, the Company recognized asset impairment expense of $355 million. See Note 16*—Asset Impairment Expense* included in Item 1.—Financial Statements of this Form 10-Q for further information. After recognizing this impairment expense, the carrying value of long-lived assets and current assets held-for-sale that were assessed for impairment totaled $2.5 billion at September 30, 2024.

Events or changes in circumstances that may necessitate recoverability tests and potential impairments of long-lived assets may include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, evolving industry expectations to transition away from fossil fuel sources for generation, or an expectation it is more likely than not the asset will be disposed of before the end of its estimated useful life.

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Tax Asset Realizability — Certain AES Chilean businesses have recorded net deferred tax assets ("DTA") of $235 million relating primarily to net operating loss carryforwards, which are not subject to expiration. Their realization is dependent on generating sufficient taxable income. At this time, management believes it is more likely than not that all of the DTA will be realized; however, it could be reduced by way of valuation allowance in the near term if estimates of future taxable income are reduced.

Environmental

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion residuals) and certain air emissions, such as SO2, NOx, particulate matter, mercury, and other hazardous air pollutants, and species and habitat protections. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules and regulations; and Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses included in the 2023 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 emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels. It is too early to determine the impact of the final FIP, but it may result in the need to purchase additional allowances or make operational adjustments. On June 27, 2024, the U.S. Supreme Court issued an order granting a stay of the EPA’s 2023 Federal Implementation Plan ("FIP") pending resolution of legal challenges to the FIP.

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

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

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

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

On July 8, 2019, the EPA published the final Affordable Clean Energy (“ACE”) Rule which would have established CO2 emission rules for existing power plants under CAA Section 111(d) and would have replaced the EPA's 2015 Clean Power Plan Rule (“CPP”). However, on January 19, 2021, the D.C. Circuit vacated and remanded the ACE Rule. Subsequently, on June 30, 2022, the Supreme Court reversed the judgment of the D.C. Circuit Court and remanded for further proceedings consistent with its opinion holding that the “generation shifting” approach in the CPP exceeded the authority granted to the EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate, holding pending challenges to the ACE Rule in abeyance while the EPA developed a replacement rule. On May 23, 2023, the EPA published a proposed rule that would vacate the ACE Rule and proposed New Source Performance Standards (“NSPSs”) that would establish emissions guidelines in the form of CO2 emissions limitations for certain existing electric generating units (“EGUs”) and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as the EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operation to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s. On May 9, 2024, the EPA published the final rule regulating GHGs from existing EGUs pursuant to Section 111(d) of the Clean Air Act and effective on July 8, 2024. Existing EGUs are those that were constructed prior to January 8, 2014. Depending on various EGU-specific factors, the bases of emissions guidelines for natural gas-fired units include the use of uniform fuels and routine methods of operation and maintenance and the bases of emissions guidelines for coal-fired units include 40% natural gas co-firing or carbon capture and sequestration with 90% capture of CO2 depending on the date that coal operations cease. Specific standards for performance for EGUs will be established through a State Plan (or a Federal Plan if a state were to not submit an approvable plan). The May 2024 rule is subject to legal challenges. On October 16, 2024, the U.S. Supreme Court denied emergency stay applications. The impact of the rules, the results of further proceedings, and potential future greenhouse gas emissions regulations remain uncertain but could be material.

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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 include interpretations regarding implementation of the CCR Rule. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. On June 28, 2024, the D.C. Circuit dismissed the challenges. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

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

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

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

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

Certain AES Southland OTC units were required to be retired to provide interconnection capacity and/or emissions credits prior to startup of new (air cooled) generating units, and the remaining AES OTC generating units in California have been or will be shut down and permanently retired by the applicable OTC Policy compliance dates

64 | The AES Corporation | September 30, 2024 Form 10-Q

for the respective units. The SWRCB OTC Policy currently requires the shutdown and permanent retirement of the remaining OTC generating units at AES Huntington Beach, LLC and AES Alamitos, LLC by December 31, 2026, as extended in support of grid reliability. This extension compliance date is contingent upon the facilities participating in the Strategic Reserve established by AB 205.

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

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

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, the EPA published a proposed rule revising the 2020 Reconsideration Rule. On May 9, 2024, the EPA published a final rule which became effective on July 8, 2024. The final rule established more stringent best available technology limits for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate and established a new set of definitions and new limits for combustion residual leachate and legacy wastewater. The May 2024 rule is subject to legal challenges. On October 10, 2024, the Eighth Circuit Court denied stay applications. It is too early to determine whether any outcome of litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition, and results of operations.

Capital Resources and Liquidity

Overview

As of September 30, 2024, the Company had unrestricted cash and cash equivalents of $1.9 billion, of which $6 million was held at the Parent Company and qualified holding companies. The Company had $62 million in short-term investments, held primarily at subsidiaries, and restricted cash and debt service reserves of $640 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $22.5 billion and $6.5 billion, respectively. Of the $3.2 billion of our current non-recourse debt, $2.9 billion was presented as such because it is due in the next twelve months and $330 million relates to debt considered in default. AES Puerto Rico is in payment default. See Note 8—Debt in Item 1.—Financial Statements of this Form 10-Q 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, 2024, the Company also had $698 million outstanding related to supplier financing arrangements, which are classified as Supplier financing arrangements on the Condensed Consolidated Balance Sheets.

65 | The AES Corporation | September 30, 2024 Form 10-Q

We expect current maturities of non-recourse debt, recourse debt, and amounts due under supplier financing arrangements to be repaid from net cash provided by operating activities of the subsidiary to which the liability relates, through opportunistic refinancing activity, or some combination thereof. We have $1.7 billion in recourse debt which matures within the next twelve months, including $611 million in outstanding borrowings under the commercial paper program. Furthermore, we have $447 million due under supplier financing arrangements that have a Parent Company guarantee. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions, or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other factors. The amounts involved in any such repurchases may be material.

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

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material unhedged exposure to variable interest rate debt relates to $200 million in senior unsecured term loans. Additionally, commercial paper issuances are short-term in nature and subject the Parent Company to interest rate risk at the time of refinancing the paper. On a consolidated basis, of the Company’s $29.3 billion of total gross debt outstanding as of September 30, 2024, approximately $9.1 billion accrues interest at variable rates. The Company actively hedges its current and expected variable rate exposure through a combination of currently effective and forward starting interest rate swaps. As of September 30, 2024, the total maximum outstanding amount of hedges protecting the company against variable rate exposure was $8.9 billion. These hedges generally provide economic protection through the entire expected life of the projects, regardless of the type of debt issued to finance construction or refinance the projects in the future. In addition, AES Brasil holds $2.3 billion of floating rate non-recourse debt, which is classified in Current held-for-sale liabilities and Noncurrent held-for-sale liabilities on the Condensed Consolidated Balance Sheets as of September 30, 2024, 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, 2024, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $4.3 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).

Some counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. As of September 30, 2024, we had $237 million in letters of credit outstanding provided under our unsecured credit facilities, $290 million in letters of credit under bilateral agreements, and $24 million in letters of credit outstanding provided under our revolving credit facility. These letters

66 | The AES Corporation | September 30, 2024 Form 10-Q

of credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the quarter ended September 30, 2024, the Company paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.

Additionally, in connection with certain project financings, some of the Company's subsidiaries have expressly undertaken limited obligations and commitments. These contingent contractual obligations are issued at the subsidiary level and are non-recourse to the Parent Company. As of September 30, 2024, the maximum undiscounted potential exposure to guarantees issued by our subsidiaries was $2.6 billion, including $1.6 billion of customary payment guarantees under EPC contracts and other agreements, and $996 million of tax equity financing related guarantees. In addition, as of September 30, 2024, our subsidiaries had $1.9 billion of letters of credit outstanding.

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

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

Long-Term Receivables

As of September 30, 2024, the Company had approximately $97 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, 2025, or one year from the latest balance sheet date. Noncurrent receivables in the U.S. pertain to the sale of the Redondo Beach land. Noncurrent receivables in Chile pertain primarily to revenues recognized on regulated energy contracts that were impacted by the Stabilization Funds created by the Chilean government. See Note 5*—Financing Receivables* in Item 1.—Financial Statements of this Form 10-Q for further information.

As of September 30, 2024, the Company had approximately $1 billion of loans receivable primarily related to the Mong Duong facility in Vietnam, which was constructed under a build, operate, and transfer contract. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25-year term of the plant’s PPA. As of September 30, 2024, Mong Duong met the held-for-sale criteria and the loan receivable balance of $1 billion, net of CECL reserves of $24 million, was classified in held-for-sale assets. Of the loan receivable balance, $118 million was classified in Current held-for-sale assets, and $873 million was classified in Noncurrent held-for-sale assets on the Condensed Consolidated Balance Sheets. See Note 14*—Revenue* in Item 1.—Financial Statements of this Form 10-Q for further information.

Cash Sources and Uses

The primary sources of cash for the Company in the nine months ended September 30, 2024 were debt financings, cash flows from operating activities, purchases under supplier financing arrangements, and sales to noncontrolling interests. The primary uses of cash in the nine months ended September 30, 2024 were capital expenditures, repayments of debt, 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, 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

67 | The AES Corporation | September 30, 2024 Form 10-Q

of debt, capital expenditures, repayments of obligations under supplier financing arrangements, and purchases of short-term investments.

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


	Nine Months Ended September 30,
Cash Sources:	2024		2023
Borrowings under the revolving credit facilities	$	5,652	$	3,939
Issuance of non-recourse debt	5,199		1,784
Net cash provided by operating activities	1,664		2,309
Purchases under supplier financing arrangements	1,211		1,307
Issuance of recourse debt	950		1,400
Sales to noncontrolling interests	869		371
Sale of short-term investments	731		1,002
Commercial paper borrowings (repayments), net	611		604



Proceeds from the sale of business interests, net of cash and restricted cash sold	11		98


Contributions from noncontrolling interests	137		63
Total Cash Sources	$	17,035	$	12,877

Cash Uses:

Capital expenditures	$	(5,665)	$	(5,295)
Repayments under revolving credit facilities	(4,051)		(2,730)
Repayments of non-recourse debt	(3,311)		(1,262)
Repayments of obligations under supplier financing arrangements	(1,412)		(1,099)
Purchase of short-term investments	(725)		(764)

Dividends paid on AES common stock	(361)		(333)
Distributions to noncontrolling interests	(165)		(173)

Purchase of emissions allowances	(157)		(161)


Acquisitions of business interests, net of cash and restricted cash sold	(79)		(311)

Other	(540)		(501)
Total Cash Uses	$	(16,466)	$	(12,629)
Net increase in Cash, Cash Equivalents, and Restricted Cash	$	569	$	248

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):	2024		2023		$ Change
Operating activities	$	1,664	$	2,309	$	(645)
Investing activities	(6,089)		(5,673)		(416)
Financing activities	5,187		3,740		1,447

Operating Activities

Net cash provided by operating activities decreased $645 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023.

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.

68 | The AES Corporation | September 30, 2024 Form 10-Q

Adjusted net income increased $84 million, primarily due to higher margins at our Utilities SBU and proceeds from the transfer of U.S. investment tax credits; partially offset by lower margins at our Renewables and Energy Infrastructure SBUs, an increase in interest expense, and a decrease in interest income.
Change in working capital decreased $729 million, primarily due to an increase in receivables due to timing of billings and collections, and higher coal consumption coupled with lower coal prices in the prior year; partially offset by the impact of lower coal purchases on accounts payable, and a decrease in other assets due to the sale of financing receivables under the Warrior Run PPA termination agreement.

Investing Activities

Net cash used in investing activities increased $416 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023.

Investing Cash Flows

(in millions)

144

Cash used for short-term investing activities increased $232 million, primarily as a result of lower net short-term investment sales at our Renewables SBU.
Proceeds from sales of business interests decreased $87 million, primarily due to the prior year selldown of sPower OpCo B.
Acquisitions of business interests decreased $232 million, primarily due to the prior year acquisitions of Bellefield and Bolero Solar Park at AES Clean Energy and AES Andes, respectively, partially offset by the current year acquisition of Hoosier Wind at AES Indiana.
Capital expenditures increased $370 million, discussed further below.

Capital Expenditures

(in millions)

759

69 | The AES Corporation | September 30, 2024 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 $364 million, primarily driven by an increase in renewables project investments in the U.S. and Chile and higher transmission and distribution project investments at our Utilities SBU; partially offset by lower expenditures in Brazil primarily due to the completion of the Cajuina wind projects.
Maintenance expenditures increased $5 million, primarily due to higher expenditures at Southland due to the extension of compliance dates for the OTC units, partially offset by the timing of maintenance activities at our Renewables SBU.

Financing Activities

Net cash provided by financing activities increased $1.4 billion for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023.

Financing Cash Flows

(in millions)

148

See Notes 1—Financial Statement Presentation, 8—Debt, and 12—Equity in Item 1.—Financial Statements of this Form 10-Q for more information regarding significant supplier financing arrangements, debt, and equity transactions, respectively.

*•*The $1.4 billion impact from non-recourse debt transactions is mainly due to an increase in borrowings at AES Indiana, AES Andes, and AES Clean Energy Development.

The $857 million impact from the Parent Company revolver is due to higher net borrowings in the current period.
The $498 million impact from sales to noncontrolling interest is primarily due to an increase in proceeds received at AES Clean Energy from the sales of ownership in project companies to tax equity investors.

*•*The $465 million impact from non-recourse revolvers is primarily due to higher net repayments at our Energy Infrastructure and Utilities SBUs.

The $450 million impact from recourse debt is primarily due to the prior year issuance of a bridge loan at AES Clean Energy, which was fully guaranteed by the Parent Company, partially offset by an increase in issuances at the Parent Company in the current period.
The $409 million impact from supplier financing arrangements is primarily due to higher net repayments at our Renewables SBU.

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

70 | The AES Corporation | September 30, 2024 Form 10-Q

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. The Parent Company credit facility and commercial paper program are generally used for short-term cash needs to bridge the timing of distributions from subsidiaries. Cash requirements at the Parent Company level are primarily to fund interest and principal repayments of debt, construction commitments, other equity commitments, acquisitions, taxes, Parent Company overhead and development costs, and dividends on common stock.

The Company defines Parent Company Liquidity as cash available to the Parent Company, including cash at qualified holding companies, plus available borrowings under our existing credit 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, 2024		December 31, 2023
Consolidated cash and cash equivalents	$	1,919	$	1,426
Less: Cash and cash equivalents at subsidiaries	(1,913)		(1,393)
Parent Company and qualified holding companies’ cash and cash equivalents	6		33
Commitments under the Parent Company credit facility	1,500		1,500
Less: Letters of credit under the credit facility	(24)		(124)
Less: Borrowings under the credit facility	(530)		—
Less: Borrowings under the commercial paper program	(611)		—
Borrowings available under the Parent Company credit facility	335		1,376
Total Parent Company Liquidity	$	341	$	1,409

The Parent Company paid dividends of $0.1725 per outstanding share to its common stockholders during the first, second, and third quarters of 2024 for dividends declared in December 2023, February 2024, and July 2024, 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 $6.5 billion and $4.5 billion as of September 30, 2024 and December 31, 2023, respectively. See Note 8—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 2023 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 2023 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, 2024, we were in compliance with these covenants at the Parent Company level.

Non-Recourse Debt

While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

71 | The AES Corporation | September 30, 2024 Form 10-Q

reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
triggering our obligation to make payments under any financial guarantee, letter of credit, or other credit support we have provided to or on behalf of such subsidiary;
causing us to record a loss in the event the lender forecloses on the assets; and
triggering defaults in our outstanding debt at the Parent Company.

For example, our revolving credit 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 $3.2 billion. The portion of current debt related to such defaults was $330 million at September 30, 2024, all of which was non-recourse debt related to five subsidiaries: AES Puerto Rico, AES Mexico Generation Holdings, AES Ilumina, AES Jordan Solar, and a project entity at AES Clean Energy Development. AES Puerto Rico is in payment default on its long-term debt and preferred shares due to failure to implement the cash sweep mechanism in accordance with the terms of the loan agreements. AES Puerto Rico is working with the noteholders to resolve this matter. All other subsidiary defaults listed are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants or other requirements contained in the non-recourse debt documents of the applicable subsidiary. See Note 8—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, 2024, in order for such defaults to trigger an event of default or permit acceleration under the Parent Company’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Parent Company’s revolving credit agreement as any business that contributed 20% or more of the Parent Company’s total cash distributions from businesses for the four most recently ended fiscal quarters. As of September 30, 2024, none of the defaults listed above resulted in a cross-default under the recourse debt of the Parent Company. Furthermore, none of the non-recourse debt in default listed above is guaranteed by the Parent Company.

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 2023 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 2023 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, if different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that these remain as critical accounting policies as of and for the nine months ended September 30, 2024.

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