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 following discussion and analysis of our financial condition and results of operations should be read together with the condensed consolidated financial statements and the notes included in Part I, Item 1 Financial Statements.

Significant Activities and Events and Items Influencing Future Performance

Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings has agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for $3.248 billion in cash subject to adjustment based on Vistra Vision cash distributions paid prior to closing (collectively, the Transaction). The Transaction is expected to close on December 31, 2024 (the Closing Date), subject to the satisfaction of certain closing conditions, at which time Vistra Vision Holdings will own 100% of the equity interests in Vistra Vision. See Note 2 to the Financial Statements for more information concerning the redeemable noncontrolling interest.

Comanche Peak Nuclear Plant License Renewal

In July 2024, our application for license renewal at our two-unit Comanche Peak Nuclear Plant was approved by the NRC. The licenses for Units 1 and 2 now extend into 2050 and 2053, respectively, an additional 20 years beyond our original licenses.

Planned Gas-Fueled Dispatchable Power in ERCOT

In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity in west, central and north Texas consisting of the following projects:

Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry.
Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.
Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.

The announcement is based on market reforms that policymakers passed in the 2023 Texas legislative session and that ERCOT and the PUCT are currently implementing. These market reforms are focused on grid reliability and proper market signals, and if successfully implemented have the potential to offer the regulatory framework needed to provide Vistra the confidence to make the long-term investments in these capacity projects. In addition, in July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above. In August 2024, the PUCT notified Vistra that an application for one of its west Texas advanced simple-cycle peaking plants was selected for due diligence as part of the Texas Energy Fund loan program. An invitation to due diligence does not mean an applicant is awarded a loan. Vistra's decision to move forward with the new west Texas gas plant project is contingent upon supportive market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation.

Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger combines Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business. The cash consideration for Energy Harbor Merger was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility, the Receivables Facility and the Repurchase Facility. See Note 2 to the Financial Statements for more information concerning the Energy Harbor Merger.

Inflation Reduction Act of 2022

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit. The IRA also implements a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to $15/MWh, subject to phase out as power prices increase above $25/MWh (each subject to annual inflation adjustments). Treasury regulations are expected to further define the scope of the legislation in many important respects in the coming months, including critical guidance interpreting the nuclear PTC. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance. As discussed in Note 1, we have not recognized any revenues or receivables related to the IRC Section 45U credits through September 30, 2024, as we await U.S. Treasury and Internal Revenue service guidance on how to interpret gross receipts in the calculation of the nuclear PTC. This guidance could have a significant impact on our estimates. Assuming an interpretation of gross receipts which excludes hedges from the calculation, our total PTC revenues for 2024 could be approximately $500 million. The amount of nuclear PTCs we record could be material to our 2024 results. We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes.

Repurchase of TRA Rights and Preferred Stock Issuance

On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH, whereby we issued TRA rights to these former first-lien creditors of TCEH entitled to receive them under the Plan of Reorganization (TRA Rights). The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (i) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (ii) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.

Vistra began a series of repurchases of TRA Rights (Repurchase) from certain registered holders of the TRA Rights (Selling Holders) in December 2023. In connection with the Repurchase, holders of approximately 74% of the outstanding TRA Rights consented to certain amendments to the TRA which were effected in an Amended and Restated Tax Receivables Agreement (A&R TRA), dated as of December 29, 2023. Such amendments to the TRA included (i) the removal of the Company's obligation to provide registered holders of the TRA Rights (Holders) with regular reporting and access to information, (ii) limitations on the transferability of the TRA Rights, (iii) removal of certain obligations of the Company in the event it incurs indebtedness and (iv) a change to the definition of "Change of Control."

During December 2023, we repurchased approximately 317 million TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $476 million. The consideration for the December 31, 2023 Repurchase was conveyed through the issuance of 476,081 shares of Vistra Series C Preferred Stock to the Selling Holders.

On January 11, 2024, we repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $65 million using cash on hand.

On January 31, 2024, we announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business of February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase. On the Early Tender Date the Company repurchased TRA Rights in exchange for total consideration of $83 million and on February 28, 2024 additional TRA Rights were repurchased under the cash tender offer for total consideration of $3 million or $1.45 per TRA Right accepted for purchase.

As of September 30, 2024, we have repurchased an aggregate 98% of the initial issuance of TRA Rights upon Emergence, of which 8,033,789 TRA Rights remain outstanding. See Note 12 to the Financial Statements for details of the TRA and Note 15 to the Financial Statements for details of the Series C Preferred Stock.

Macroeconomic Conditions

Historically, the base case assumption for U.S. electricity demand was for modest growth driven by the interplay of growth in population, industrial activity (such as an on-shore manufacturing) and new demand sources (such as electric vehicles), partially offset by continued advancements in energy efficiency. Multiple demand drivers such as emergence of large load data centers and electrification of oil field operations (specifically the Permian Basin of west Texas), have accelerated load growth in the geographic regions we serve. We are in various discussions with interested counterparties for the potential sale of power from our nuclear and gas facilities pursuant to long-term agreements to supply large load facilities. Such potential transactions are subject to certain risks and uncertainties, including potential regulatory review and/or approval and adverse legislative action, which could impact the timing of, and our ability to consummate, a potential transaction.

The industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased (i) the lead time to procure certain materials necessary to maintain, and (ii) the labor costs associated with maintenance activity on our natural gas, nuclear and coal fleet. We are proactively managing the increased costs of materials and supply chain disruptions and continuing to prudently re-evaluate the business cases and timing of our planned development projects, which has resulted in a deferral of some of our planned capital spend for our renewables projects. In addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the impact of the IRA. The inflationary environment continues to drive elevated interest rates, resulting in increased refinancing or borrowing costs, including future non-recourse financing for our development projects and future refinancing expected in connection with debt due in 2025 and beyond.

We continue to closely monitor developments in the Russia and Ukraine conflict, specifically with regards to, (i) sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and (ii) actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. The Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress and signed into law by President Biden and took effect on August 11, 2024. The PRUI Act prohibits importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. Our 2024 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refuel schedules. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance, and therefore, we have enough nuclear fuel contracted to support all our refueling needs through 2029. We continue to take affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facilities through potential Russian supply disruption.

Capacity Markets — PJM Auction Results

In July 2024, Vistra reported its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2025-2026, and the table below lists clearing price per MW-day and our cleared capacity volumes by zone:


	Clearing Price per MW-day		East Segment MW Cleared	Sunset Segment MW Cleared	Total MW Cleared
RTO zone	$	269.92	3,774	—	3,774
ComEd zone	$	269.92	1,189	967	2,156
DEOK zone	$	269.92	111	835	946
EMAAC zone	$	269.92	656	—	656
MAAC zone	$	269.92	471	—	471
ATSI zone	$	269.92	2,044	—	2,044
DOM zone	$	444.26	208	—	208
Total			8,453	1,802	10,255

Critical Accounting Policies and Estimates

The Company's discussion and analysis of its financial position and results of operations is based upon its condensed consolidated financial statements. The preparation of these condensed consolidated financial statements requires estimation and judgment that affect the reported amounts of revenue, expenses, assets and liabilities. The Company bases its estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the accounting for assets and liabilities that are not readily apparent from other sources. If the estimates differ materially from actual results, the impact in the condensed consolidated financial statements may be material. Except as discussed below, the Company's critical accounting policies are disclosed in our 2023 Form 10-K.

Business Combinations

Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 2 to the Financial Statements. The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant and equipment and asset retirement obligations:

Property, Plant and Equipment

The fair value of each power plant acquired was estimated using a combination of an income approach and a market approach. The income approach is based on the discounted cash flow method that uses (i) our estimates of forecasted future growth and long term prices of electricity, capacity and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses, and taxes, as well as working capital and capital asset requirements. Projected cash flows are then discounted to a present value employing a discount rate that properly accounts for the estimated market weighted-average cost of capital, as well as any risks unique to the subject cash flows. These estimates are subjective in nature and require judgement to interpret market data. The market valuation method used prices paid for a reasonably similar asset by other purchasers in the relevant market, with adjustments relating to physical differences in the asset as well as their locations.

Nuclear Decommissioning Asset Retirement Obligation

To estimate our nuclear decommissioning asset retirement obligation on assets acquired from Energy Harbor, we used a discounted cash flow model based on our estimates of cost escalation factors and discount rates, and considered multiple decommissioning scenarios: (i) DECON, which assumes major decommissioning activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently decontaminated within 60 years after the facility ceases operations. The probability-weighted estimated future cash flows were discounted using our specific credit-adjusted, risk-free rates which reflected the secured nature of the obligation due to acquired investments in NDTs which are intended to fund the future decommissioning obligations.

RESULTS OF OPERATIONS

Net income increased $1.335 billion to Net income of $1.837 billion in the three months ended September 30, 2024 compared to the three months ended September 30, 2023. Net income increased $0.646 billion to Net income of $2.322 billion for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. For additional information see the following discussion of our results of operations.

EBITDA and Adjusted EBITDA

In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.

These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review the condensed consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).

Vistra Consolidated Financial Results — Three Months Ended September 30, 2024 Compared to the Three Months Ended September 30, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended September 30, 2024:


	Three Months Ended September 30, 2024
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	4,251	$	4,104	$	1,524	$	242	$	469	$	1	$	(4,303)	$	6,288
Fuel, purchased power costs and delivery fees	(5,117)		(461)		(685)		(46)		(200)		(1)		4,303		(2,207)
Operating costs	(47)		(237)		(234)		(16)		(67)		(14)		(1)		(616)
Depreciation and amortization	(31)		(153)		(223)		(22)		(20)		—		(17)		(466)
Selling, general and administrative expenses	(266)		(38)		(20)		(7)		(14)		(10)		(56)		(411)

Operating income (loss)	(1,210)		3,215		362		151		168		(24)		(74)		2,588
Other income	—		24		98		1		—		8		8		139
Other deductions	—		(1)		—		—		(1)		(1)		—		(3)
Interest expense and related charges	(16)		11		8		1		(4)		(1)		(331)		(332)

Income (loss) before income taxes	(1,226)		3,249		468		153		163		(18)		(397)		2,392
Income tax expense	—		—		—		—		—		—		(555)		(555)
Net income (loss)	$	(1,226)	$	3,249	$	468	$	153	$	163	$	(18)	$	(952)	$	1,837
Income tax expense	—		—		—		—		—		—		555		555
Interest expense and related charges (a)	16		(11)		(8)		(1)		4		1		331		332
Depreciation and amortization (b)	31		181		318		22		20		—		17		589
EBITDA before Adjustments	(1,179)		3,419		778		174		187		(17)		(49)		3,313
Unrealized net (gain) loss resulting from hedging transactions	1,275		(2,705)		(239)		(101)		(83)		(2)		—		(1,855)

Fresh start/purchase accounting impacts	1		1		(4)		—		—		—		—		(2)


Non-cash compensation expenses	—		—		—		—		—		—		23		23
Transition and merger expenses	—		1		1		—		—		—		23		25



Decommissioning-related activities (c)	—		7		(73)		—		2		—		—		(64)


ERP system implementation expenses	1		1		—		—		—		1		—		3
Other, net	4		(2)		1		3		(1)		1		(22)		(16)
Adjusted EBITDA	$	102	$	722	$	464	$	76	$	105	$	(17)	$	(25)	$	1,427

(a)Includes $84 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $28 million and $95 million, respectively, in Texas and East segments.

(c)Represents net of all NDT income (loss) of the PJM nuclear facilities, ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended September 30, 2023:


	Three Months Ended September 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	3,383	$	1,517	$	651	$	344	$	224	$	—	$	(2,033)	$	4,086
Fuel, purchased power costs and delivery fees	(2,837)		(707)		(376)		(46)		(176)		(1)		2,034		(2,109)
Operating costs	(36)		(217)		(65)		(14)		(63)		(15)		(1)		(411)
Depreciation and amortization	(26)		(132)		(161)		(22)		(16)		—		(18)		(375)
Selling, general and administrative expenses	(237)		(32)		(20)		(6)		(11)		(7)		(44)		(357)

Operating income (loss)	247		429		29		256		(42)		(23)		(62)		834
Other income	—		4		—		8		—		7		13		32
Other deductions	—		—		—		—		(2)		—		(1)		(3)
Interest expense and related charges	(2)		5		—		—		—		(1)		(145)		(143)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(49)		(49)
Income (loss) before income taxes	245		438		29		264		(44)		(17)		(244)		671
Income tax expense	—		—		—		—		—		—		(169)		$	(169)
Net income (loss)	$	245	$	438	$	29	$	264	$	(44)	$	(17)	$	(413)	$	502
Income tax expense	—		—		—		—		—		—		169		169
Interest expense and related charges (a)	2		(5)		—		—		—		1		145		143
Depreciation and amortization (b)	26		158		161		22		16		—		18		401
EBITDA before Adjustments	273		591		190		286		(28)		(16)		(81)		1,215
Unrealized net (gain) loss resulting from hedging transactions	(97)		356		125		(203)		110		(8)		—		283


Impacts of Tax Receivable Agreement	—		—		—		—		—		—		49		49

Non-cash compensation expenses	—		—		—		—		—		—		21		21
Transition and merger expenses	—		—		—		—		—		—		22		22



PJM capacity performance default (c)	—		—		(3)		—		4		—		—		1
Winter Storm Uri impacts (d)	(8)		1		—		—		—		—		—		(7)
Other, net	5		2		3		4		16		—		(25)		5
Adjusted EBITDA	$	173	$	950	$	315	$	87	$	102	$	(24)	$	(14)	$	1,589

(a)Includes $43 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $26 million in the Texas segment.

(c)Represents change in estimate of anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott.

(d)Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri.

GAAP operating income increased $1.754 billion to operating income of $2.588 billion in the three months ended September 30, 2024 compared to the three months ended September 30, 2023. The primary favorable drivers for the increase are (i) a $2.138 billion change in unrealized mark-to-market activity as results for the three months ended September 30, 2024 were favorably impacted by $1.855 billion in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the the three months ended September 30, 2023 compared to $283 million in pre-tax unrealized mark-to-market losses on derivative positions due to power forward market curves moving up in Texas in the three months ended September 30, 2023 and (ii) addition of the Energy Harbor assets in East. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below. These favorable variances are partially offset by lower realized generation margins in Texas due to fewer scarcity pricing events compared to 2023 and a decrease in retail operating income which is driven by a shift in the seasonality of margins on retail contracts as summer supply costs increased compared to 2023, partially offset by the addition of Energy Harbor retail.

The following table presents operational performance of our retail and generation segments:


	Three Months Ended September 30,
	Retail				Texas				East				West				Sunset
	2024		2023		2024		2023		2024		2023		2024		2023		2024		2023
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	22,193		22,643
Sales volumes in Northeast/Midwest	17,864		7,935
Total retail electricity sales volumes	40,057		30,578
Production volumes (GWh):
Natural gas facilities					15,152		15,635		17,135		16,976		996		1,465
Lignite and coal facilities					6,105		6,743										5,908		5,038
Nuclear facilities					5,217		5,210		8,677
Solar facilities					233		247
Capacity factors:
CCGT facilities					78.3	%	77.2	%	70.5	%	69.2	%	44.2	%	65.0	%
Lignite and coal facilities					71.8	%	79.3	%									58.4	%	49.8	%
Nuclear facilities					98.5	%	98.3	%	97.1	%
Weather - percent of normal (a):
Cooling degree days	100%		122	%	102	%	121	%	96	%	97	%	98	%	93	%	99	%	112	%
Heating degree days	—	%	—	%	—	%	—	%	71	%	102	%	—	%	—	%	22	%	—	%

(a)Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data.


	Three Months Ended September 30,							Three Months Ended September 30,
	2024			2023				2024		2023
Market pricing						Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	26.94		$	109.32	PJM West Hub		$	50.03	$	42.93
			AEP Dayton Hub	$	41.07	$	40.00
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.08		$	2.58	NYISO Zone C		$	39.70	$	35.46
			Massachusetts Hub	$	46.19	$	39.88
Average natural gas price (a):						Indiana Hub		$	40.71	$	42.99
TetcoM3 ($/MMBtu)	$	1.50		$	1.39	Northern Illinois Hub		$	37.82	$	39.36
Algonquin Citygates ($/MMBtu)	$	1.75		$	1.93	CAISO NP15		$	44.92	$	59.65

(a) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

(b)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

The following table presents additional changes to Net income (loss) and Adjusted EBITDA for the three months ended September 30, 2024 compared to the three months ended September 30, 2023.


	Three Months Ended September 30, 2024 Compared to 2023
	Retail (a)		Texas		East (a)		West		Sunset
	(in millions)

Favorable change in realized revenue net of fuel in East driven by addition of Energy Harbor. Unfavorable change in Texas driven by lack of scarcity pricing in 2024 as compared to 2023	$	—	$	(228)	$	295	$	—	$	8
Lower margins driven by increase in power supply costs	(20)		—		—		—		—
Unfavorable change in weather impacts	(29)
Favorable impact of less Winter Storm Uri bill credits applied	6		—		—		—		—
Increase in operating costs due primarily to addition of Energy Harbor in East	—		(13)		(146)		(2)		(3)
Change in SG&A and other	(28)		13		—		(9)		(2)
Change in Adjusted EBITDA	$	(71)	$	(228)	$	149	$	(11)	$	3
Unfavorable change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East	(5)		(23)		(157)		—		(4)
Change in unrealized net gains (losses) on hedging activities (b)	(1,372)		3,061		364		(102)		193





Decommissioning related activities	—		(7)		73		—		(2)
PJM capacity performance default impacts	—		—		(3)		—		4
Other (including interest expenses)	(23)		8		13		2		13
Change in Net income (loss)	$	(1,471)	$	2,811	$	439	$	(111)	$	207

(a) Includes amounts associated with operations acquired in the Energy Harbor Merger.

(b**)** See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.

For the three months ended September 30, 2024, other income totaled $139 million driven by NDT net gains of $95 million, insurance proceeds of $21 million and interest income of $9 million. For the three months ended September 30, 2023, other income totaled $32 million driven by interest income of $16 million and insurance settlements of $12 million.

Consolidated interest expense and related charges increased $189 million in the three months ended September 30, 2024 compared to the three months ended September 30, 2023 due to (i) unrealized mark-to-market losses on interest rate swaps of $84 million in 2024 compared to unrealized mark-to-market gains on interest rate swaps of $43 million in 2023 due to a decrease in interest rates in the three months ended September 30, 2024 compared to an increase in interest rates in the three months ended September 30, 2023 and (ii) an increase in interest paid/accrued of $83 million driven by higher average borrowings and rates in 2024. See Note 17 to the Financial Statements.

Vistra Consolidated Financial Results — Nine Months Ended September 30, 2024 Compared to the Nine Months Ended September 30, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the nine months ended September 30, 2024:


	Nine Months Ended September 30, 2024
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	9,913	$	4,716	$	3,354	$	729	$	1,095	$	1	$	(6,621)	$	13,187
Fuel, purchased power costs and delivery fees	(8,724)		(1,189)		(1,559)		(167)		(501)		(2)		6,622		(5,520)
Operating costs	(118)		(732)		(596)		(54)		(199)		(41)		(2)		(1,742)
Depreciation and amortization	(85)		(418)		(631)		(64)		(58)		—		(50)		(1,306)
Selling, general and administrative expenses	(715)		(112)		(61)		(17)		(36)		(31)		(165)		(1,137)
Impairment of long-lived assets	—		—		—		—		—		—		—		—
Operating income (loss)	271		2,265		507		427		301		(73)		(216)		3,482
Other income	—		32		179		2		—		14		65		292
Other deductions	(1)		(3)		—		—		(2)		(2)		(2)		(10)
Interest expense and related charges	(38)		33		7		1		(3)		(3)		(740)		(743)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(5)		(5)
Income (loss) before income taxes	232		2,327		693		430		296		(64)		(898)		3,016
Income tax expense	—		—		—		—		—		—		(694)		(694)
Net income (loss)	$	232	$	2,327	$	693	$	430	$	296	$	(64)	$	(1,592)	$	2,322
Income tax expense	—		—		—		—		—		—		694		694
Interest expense and related charges (a)	38		(33)		(7)		(1)		3		3		740		743
Depreciation and amortization (b)	85		498		820		64		58		—		50		1,575
EBITDA before Adjustments	355		2,792		1,506		493		357		(61)		(108)		5,334
Unrealized net (gain) loss resulting from commodity hedging transactions	489		(1,452)		(404)		(308)		(42)		(8)		—		(1,725)

Fresh start/purchase accounting impacts	—		1		(10)		—		2		—		(14)		(21)
Impacts of Tax Receivable Agreement (c)	—		—		—		—		—		—		(5)		(5)

Non-cash compensation expenses	—		—		—		—		—		—		76		76
Transition and merger expenses	2		1		7		—		—		—		75		85



Decommissioning-related activities (d)	—		17		(116)		1		6		—		—		(92)


ERP system implementation expenses	7		6		3		1		2		2		—		21
Other, net	10		4		2		7		(7)		1		(85)		(68)
Adjusted EBITDA	$	863	$	1,369	$	988	$	194	$	318	$	(66)	$	(61)	$	3,605

(a)Includes $26 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $80 million and $189 million, respectively, in Texas and East segments.

(c)Includes $10 million gain recognized on the repurchase of TRA Rights in the nine months ended September 30, 2024 (see Note 12 to the Financial Statements).

(d)Represents net of all NDT income (loss) of the PJM nuclear facilities, ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the nine months ended September 30, 2023:


	Nine Months Ended September 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	8,161	$	3,061	$	3,305	$	799	$	1,366	$	—	$	(4,991)	$	11,701
Fuel, purchased power costs and delivery fees	(6,879)		(1,546)		(1,494)		(226)		(599)		(2)		4,992		(5,754)
Operating costs	(93)		(680)		(218)		(43)		(190)		(52)		(1)		(1,277)
Depreciation and amortization	(78)		(390)		(488)		(56)		(45)		—		(52)		(1,109)
Selling, general and administrative expenses	(630)		(95)		(57)		(18)		(36)		(24)		(93)		(953)
Impairment of long-lived assets	—		—		—		—		(49)		—		—		(49)
Operating income (loss)	481		350		1,048		456		447		(78)		(145)		2,559
Other income	—		32		2		17		1		105		17		174
Other deductions	—		(1)		—		—		(4)		—		(4)		(9)
Interest expense and related charges	(19)		15		—		8		(2)		(4)		(448)		(450)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(128)		(128)
Income (loss) before income taxes	462		396		1,050		481		442		23		(708)		2,146
Income tax expense	—		—		(1)		—		—		—		(469)		(470)
Net income (loss)	$	462	$	396	$	1,049	$	481	$	442	$	23	$	(1,177)	$	1,676
Income tax expense	—		—		1		—		—		—		469		470
Interest expense and related charges (a)	19		(15)		—		(8)		2		4		448		450
Depreciation and amortization (b)	78		458		488		56		45		—		52		1,177
EBITDA before Adjustments	559		839		1,538		529		489		27		(208)		3,773
Unrealized net (gain) loss resulting from commodity hedging transactions	114		703		(1,024)		(338)		(278)		(32)		—		(855)


Impacts of Tax Receivable Agreement	—		—		—		—		—		—		128		128

Non-cash compensation expenses	—		—		—		—		—		—		63		63
Transition and merger expenses	(2)		1		—		—		1		—		39		39
Impairment of long-lived assets	—		—		—		—		49		—		—		49


PJM capacity performance default impacts (c)	—		—		3		—		6		—		—		9
Winter Storm Uri impacts (d)	(46)		2		—		—		—		—		—		(44)
Other, net	17		(5)		9		5		38		(1)		(57)		6
Adjusted EBITDA	$	642	$	1,540	$	526	$	196	$	305	$	(6)	$	(35)	$	3,168

(a)Includes $65 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $68 million in Texas segment.

(c)Represents estimate of anticipated market participant defaults or settlements on initial PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott.

(d)Adjusted EBITDA impacts of Winter Storm Uri reflects the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and a reduction in the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm.

GAAP operating income increased $923 million to operating income of $3.482 billion in the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. The primary driver for the increase is an $870 million change in unrealized mark-to-market activity as results for the nine months ended September 30, 2024 were favorably impacted by $1.725 billion in pre-tax unrealized mark-to-market gains on derivative positions in the nine months ended September 30, 2024 compared to $855 million in pre-tax unrealized mark-to-market gains on commodity derivative positions due to power and natural gas forward market curves moving down more significantly in the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.

In addition to the mark-to-market impacts discussed above, operating results for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023 were impacted by additional factors including:

Favorable impacts:

Addition of Energy Harbor in March 2024 with results reflected in the East and Retail segments.
Expiration of legacy Vistra default service contracts in the East segment which resulted in higher-than-expected migration of customers at rates below prevailing wholesale market prices in the nine months ended September 30, 2023. Similar contracts acquired from Energy Harbor are reflected in the Retail segment and are a driver of the favorable 2024 Retail results.

Unfavorable impacts:

Decreases in capacity revenues primarily in the Sunset segment.
Increase in interest expense driven by higher average borrowings and unrealized mark to market losses on interest rate swaps.
Increase in depreciation and amortization expense driven by addition of assets acquired from Energy Harbor.
Increase in selling, general and administrative expenses in Retail segment and Corp. and Other driven primarily by the addition of Energy Harbor.

The following table presents operational performance of our retail and generation segments:


	Nine Months Ended September 30,
	Retail				Texas				East				West				Sunset
	2024		2023		2024		2023		2024		2023		2024		2023		2024		2023
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	57,234		54,711
Sales volumes in Northeast/Midwest	44,105		19,965
Total retail electricity sales volumes	101,339		74,676
Production volumes (GWh):
Natural gas facilities					34,504		32,809		44,267		45,470		2,921		3,741
Lignite and coal facilities					15,686		17,903										14,122		11,355
Nuclear facilities					15,260		14,471		18,438
Solar facilities					605		638
Capacity factors:
CCGT facilities					60.6	%	57.1	%	60.7	%	62.8	%	43.5	%	55.9	%
Lignite and coal facilities					62.0	%	71.0	%									46.9	%	37.9	%
Nuclear facilities					96.7	%	92.0	%	88.7	%
Weather - percent of normal (a):
Cooling degree days	107	%	115	%	108	%	114	%	105	%	89	%	91	%	78	%	100	%	110	%
Heating degree days	86	%	82	%	89	%	82	%	85	%	85	%	121	%	154	%	84	%	86	%

(a)Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data.


	Nine Months Ended September 30,							Nine Months Ended September 30,
	2024			2023				2024		2023
Market pricing						Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	25.75		$	56.26	PJM West Hub		$	41.24	$	38.20
			AEP Dayton Hub	$	36.37	$	36.16
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.19		$	2.46	NYISO Zone C		$	36.62	$	30.12
			Massachusetts Hub	$	42.77	$	41.49
Average natural gas price (a):						Indiana Hub		$	38.16	$	39.49
TetcoM3 ($/MMBtu)	$	1.98		$	1.94	Northern Illinois Hub		$	32.39	$	32.96
Algonquin Citygates ($/MMBtu)	$	2.56		$	3.02	CAISO NP15		$	38.93	$	64.35

(a) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

(b)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

For the nine months ended September 30, 2024, other income totaled $292 million driven by NDT net gains of $170 million, interest income of $50 million, insurance proceeds of $22 million and a gain of $10 million on TRA repurchases. For the nine months ended September 30, 2023, other income totaled $174 million driven by a gain of $89 million from the sale of property in Freestone County, Texas, interest income of $42 million and insurance settlements of $21 million.

Consolidated interest expense and related charges increased $293 million in the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to (i) an increase in interest paid/accrued of $228 million driven by higher average borrowings and rates in 2024 and (ii) unrealized mark-to-market losses on interest rate swaps of $26 million in 2024 compared to unrealized mark-to-market gains on interest rate swaps of $65 million in 2023 due to a decrease in interest rates in the nine months ended September 30, 2024 compared to an increase in interest rates in the nine months ended September 30, 2023. See Note 17 to the Financial Statements.

The following table presents additional changes to Net income (loss) and Adjusted EBITDA for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.


	Nine Months Ended September 30, 2024 Compared to 2023
	Retail (a)		Texas		East (a)		West		Sunset
	(in millions)

Favorable change in realized revenue net of fuel in East driven by addition of Energy Harbor and rolloff of negative margin default service contracts. Unfavorable change in Texas is driven by a decrease in realized margins due to lack of scarcity pricing events compared to 2023	$	—	$	(132)	$	780	$	19	$	19
Higher retail margins driven by increase in customers, favorable power supply cost, and addition of Energy Harbor retail contracts	260		—		—		—		—
Favorable impact of less Winter Storm Uri bill credits applied	35		—		—		—		—

Increase in plant operating costs due primarily to addition of Energy Harbor in East	—		(34)		(319)		(10)		(6)
Change in SG&A and other primarily due to increase in retail costs related to Energy Harbor	(74)		(5)		1		(11)		—
Change in Adjusted EBITDA	$	221	$	(171)	$	462	$	(2)	$	13
Unfavorable change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East	(7)		(40)		(332)		(8)		(13)
Change in unrealized net gains (losses) on hedging activities (b)	(375)		2,155		(620)		(30)		(236)
Impairment of long-lived assets	—		—		—		—		49




Decommissioning related activities	—		(17)		116		(1)		(6)
PJM capacity performance default impacts	—		—		3		—		6
Winter Storm Uri impact	(46)		2		—		—		—
Other (including interest expenses)	(23)		2		15		(10)		41
Change in Net income (loss)	$	(230)	$	1,931	$	(356)	$	(51)	$	(146)

(a) Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.

(b**)** See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.

Asset Closure Segment — Three and Nine Months Ended September 30, 2024 Compared to Three and Nine Months Ended September 30, 2023


	Three Months Ended September 30,				Favorable (Unfavorable) Change			Nine Months Ended September 30,					Favorable (Unfavorable) Change
	2024		2023				2024			2023
	(in millions)
Operating revenues	$	1	$	—	$	1		$	1		$	—	$	1
Fuel, purchased power costs and delivery fees	(1)		(1)		—			$	(2)		$	(2)	$	—
Operating costs	$	(14)	$	(15)	$	1		(41)			(52)		11

Selling, general and administrative expenses	(10)		(7)		(3)			(31)			(24)		(7)


Operating loss	(24)		(23)		(1)			(73)			(78)		5
Other income	8		7		1			14			105		(91)
Other deductions	(1)		—		(1)			(2)			—		(2)
Interest expense and related charges	(1)		(1)		—			(3)			(4)		1

Income (loss) before income taxes	(18)		(17)		(1)			(64)			23		(87)

Net income (loss)	$	(18)	$	(17)	$	(1)		$	(64)		$	23	$	(87)











Adjusted EBITDA	$	(18)	$	(24)	$	6		$	(68)		$	(6)	$	(62)

GAAP and Adjusted EBITDA results for the three and nine months ended September 30, 2024 are unfavorable compared to the three and nine months ended September 30, 2023 primarily due to other income of $89 million from the gain on sale of property in Freestone County, Texas in the second quarter of 2023.

Energy-Related Commodity Contracts and Mark-to-Market Activities

As forward power prices materially increased in 2022, our generation segments (Texas, East, West and Sunset) aggressively sold forward power for future years. We entered the 2023 and 2024 calendar years with more than 99% of our expected generation volumes hedged. While settled power prices in the three quarters of 2024 are lower than historical averages, the strategic hedging allowed us to lock in margins above what we would have been able to realize if unhedged. In the East segment, the margins we were able to lock in with hedges for the three and nine months ended September 30, 2024 are higher than the three and nine months ended September 30, 2023 which is driving the increase in realized revenue net of fuel in the generation segments along with the addition of Energy Harbor. In the Texas segment, we materially benefited in the third quarter of 2023 as we were able to sell additional power in times of scarcity when real-time prices were high. There have been minimal scarcity events and periods of high pricing in Texas in 2024 and that is the primary driver of the unfavorable change in realized revenue net of fuel. The forward power sales are also the drivers of the changes in unrealized gains/losses on hedging activities. As power prices increase/decrease in comparison to what our generation segments have sold forward, the generation segments recognize unrealized losses/gains. The retail segment procures power from the generation segments to serve future load obligations and thus changes in forward power prices have an inverse effect on unrealized mark to market for the retail segment as compared to the generation segments. In the first three quarters of 2024, we saw a decrease in forward power prices in all our generation segments compared to our hedged positions which drove material unrealized gains in those segments, partially offset by unrealized losses in our retail segment. In the first three quarters of 2023, the non-Texas generation segments also experienced a decrease in forward power prices compared to our hedged positions which resulted in unrealized gains in those segments partially offset by unrealized losses in our retail segment. In Texas, forward power prices materially increased in the three and nine months ended September 30, 2023 which resulted in unrealized losses in Texas partially offset by unrealized gains in the retail segment.

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2024 and 2023. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.725 billion and $855 million in unrealized net gains for the nine months ended September 30, 2024 and 2023, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


	Nine Months Ended September 30,
	2024		2023
	(in millions)
Commodity contract net liability as of January 1	$	(2,740)	$	(3,148)
Settlements/termination of positions (a)	1,350		1,585
Changes in fair value of positions in the portfolio (b)	375		(730)
Acquired commodity contracts (c)	(50)		—
Other activity (d)	111		(108)
Commodity contract net liability as of September 30	$	(954)	$	(2,401)

(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(losses) recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(b)Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(c)Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements).

(d)Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.

The following maturity table presents the net commodity contract liability arising from recognition of fair values as of September 30, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions.


	Maturity dates of unrealized commodity contract net liability as of September 30, 2024
Source of Fair Value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
	(in millions)
Prices actively quoted	$	(187)	$	4	$	29	$		$	(154)
Prices provided by other external sources	$	(369)	$	86	$		$		$	(283)
Prices based on models	$	(195)	$	(363)	$	38	$	3	$	(517)
Total	$	(751)	$	(273)	$	67	$	3	$	(954)

We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of September 30, 2024 were as follows:


	Balance of
	2024		2025
Nuclear/Renewable/Coal Generation:
Texas	100	%	100	%
East	100	%	66	%
Sunset	100	%	90	%
Natural Gas Generation:
Texas	100	%	100	%
East	100	%	98	%
West	100	%	99	%

Financial Condition

Cash Flows

Operating Cash Flows

Cash provided by operating activities totaled $3.210 billion and $4.572 billion in the nine months ended September 30, 2024 and 2023, respectively. The unfavorable change of $1.362 billion was primarily driven by a smaller decrease in net margin deposits (returns of cash related to commodity contracts which support our hedging strategy) as $855 million was returned in the nine months ended September 30, 2024 as compared to $2.271 billion returned in the nine months ended September 30, 2023. This unfavorable variance is partially offset by an increase in cash from realized operating income primarily due to the addition of Energy Harbor.

Depreciation and amortization — Depreciation and amortization expense, as reported as a reconciling adjustment in the condensed consolidated statements of cash flows, exceeds the amount reported in the condensed consolidated statements of operations by $585 million and $333 million for the nine months ended September 30, 2024 and 2023, respectively. This difference represents amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, as well as the amortization of intangible net assets and liabilities. These are reported under various line items in the other condensed consolidated statements of operations, including operating revenues, fuel and purchased power costs, and delivery fees (see Note 7 to the Financial Statements).

Investing Cash Flows

Cash used in investing activities totaled $4.959 billion and $1.382 billion in the nine months ended September 30, 2024 and 2023, respectively. The increase of $3.577 billion was driven primarily by (a) $3.1 billion used to fund the Energy Harbor Merger and (b) a $386 million increase in capital expenditures driven by higher nuclear fuel purchases.


	Nine Months Ended September 30,				Increase (Decrease)
	2024		2023
	(in millions)
Capital expenditures, including LTSA prepayments	$	(602)	$	(575)	$	(27)
Nuclear fuel purchases	(445)		(174)		(271)
Growth and development expenditures	(601)		(513)		(88)
Total capital expenditures	(1,648)		(1,262)		(386)
Energy Harbor acquisition (net of cash acquired)	(3,065)		—		(3,065)
Net purchases of environmental allowances	(364)		(218)		(146)


Proceeds from sales of property, plant and equipment, including nuclear fuel	137		111		26
Other investing activity	(19)		(13)		(6)
Cash used in investing activities	$	(4,959)	$	(1,382)	$	(3,577)

Financing Cash Flows

Cash used in financing activities totaled $850 million and $490 million in the nine months ended September 30, 2024 and 2023, respectively. In both periods, the primary driver of the net outflows is share repurchases and dividends partially offset by net new borrowings as detailed below.


	Nine Months Ended September 30,				Increase (Decrease)
	2024		2023
	(in millions)
Share repurchases	$	(1,021)	$	(866)	$	(155)
Issuances of long-term debt	2,200		1,750		450
Other net long-term borrowings (repayments)	(2,269)		(21)		(2,248)
Net short-term borrowings (repayments)	—		(650)		650
Net borrowings (repayments) under the accounts receivable financing facilities	750		(425)		1,175
Dividends paid to common stockholders	(230)		(228)		(2)
Dividends paid to preferred stockholders	(98)		(75)		(23)
Dividends paid to noncontrolling interest in subsidiary	(15)		—		(15)
TRA Repurchase and tender offer — return of capital	(122)		—		(122)
Other financing activity	(45)		25		(70)
Cash used in financing activities	$	(850)	$	(490)	$	(360)

Debt Activity

We remain committed to a strong balance sheet and have continued to state our objective to reduce our consolidated net leverage. We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities.

Increases in interest rates have resulted in, and will likely continue to result in, increased borrowing costs.

See Note 9 to the Financial Statements for details of the Receivables Facility, Repurchase Facility, Vistra Operations Credit Facilities, Commodity-Linked Facility and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2024:


	September 30, 2024		December 31, 2023		Change
	(in millions)
Cash and cash equivalents (a)	$	905	$	3,485	$	(2,580)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)	2,457		1,213		1,244
Vistra Operations — Commodity-Linked Facility (c)	633		1,101		(468)
Total available liquidity (d)(e)	$	3,995	$	5,799	$	(1,804)

____________

(a)See the condensed consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the nine months ended September 30, 2024. The decrease includes $3.1 billion that was used to fund the Energy Harbor Merger.

(b)The increase in availability for the nine months ended September 30, 2024 was driven by a $1.244 billion decrease in letters of credit outstanding under the facility. In October 2024, Vistra Operations amended the Revolving Credit Facility which, among other things, increased the revolving credit commitments to $3.440 billion and extended the maturity date to October 11, 2029.

(c)As of both September 30, 2024 and December 31, 2023, the borrowing bases are less than the facility limit of $1.575 billion. As of September 30, 2024, available capacity reflects the borrowing base of $633 million and no cash borrowings. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings. In October 2024, Vistra Operations amended the Commodity-Linked Facility which, among other things, increased the aggregate available commitments to $1.75 billion and extended the maturity date to October 1, 2025.

(d)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for detail on our accounts receivable financing.

(e)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC Facilities. See Note 9 to the Financial Statements for detail on our letter of credit facilities.

We believe that we will have access to sufficient liquidity to fund our other anticipated cash requirements through at least the next 12 months, including the upcoming payments associated with the acquisition of the noncontrolling interest in Vistra Vision discussed in Note 2 to the Financial Statements. Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

Including obligations assumed in the Energy Harbor Merger, our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $3.0 billion in fiscal year 2024, $4.3 billion in 2025-2026, $1.6 billion in 2027-2028 and $1.2 billion thereafter.

Capital Expenditures

Estimated 2024 capital expenditures and nuclear fuel purchases as of November 4, 2024 total approximately $2.053 billion and include:

$808 million for investments in generation and mining facilities;
$707 million for solar and energy storage development;
$361 million for nuclear fuel purchases; and
$177 million for other growth expenditures.

Share Repurchase Program

In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date. In August 2022, March 2023, February 2024 and October 2024, the Board authorized incremental amounts of $1.25 billion, $1.0 billion, $1.5 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $6.75 billion as of November 4, 2024.

The following table provides information about our repurchases of common stock for the period between January 1, 2024 and November 4, 2024:


	$6.750 billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
	(in millions, except share amounts and price paid per share)
Three Months Ended March 31, 2024	6,138,773	$	46.21	$	284
Three Months Ended June 30, 2024	3,946,797	83.31		328
Three Months Ended September 30, 2024 (a)	4,849,061	82.90		402
Nine Months Ended September 30, 2024	14,934,631	$	67.92	$	1,014	$	1,236
October 1, 2024 through November 4, 2024	500,151	126.44		63
January 1, 2024 through November 4, 2024 (b)	15,434,782	$	69.82	$	1,077	$	2,173

(a)Shares repurchased include 52,833 of unsettled shares for $6 million as of September 30, 2024.

(b)In October 2024, the Board authorized $1.0 billion for additional repurchases under the Share Repurchase Program.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 8 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 9 to the Financial Statements for discussion of the Vistra Operations Credit Facilities, the Commodity-Linked Facility, the Secured LOC Facilities and the Alternative LOC Facilities.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

As of September 30, 2024, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

$970 million in cash and Eligible Assets have been posted with counterparties as compared to $1.244 billion posted as of December 31, 2023;
$175 million in cash has been received from counterparties as compared to $45 million received as of December 31, 2023;
$2.013 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of December 31, 2023; and
$143 million in letters of credit have been received from counterparties as compared to $143 million received as of December 31, 2023.

See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules.

Income Tax Payments

In the next 12 months, we expect to make approximately $25 million in federal income tax payments, $60 million in state income tax payments and $1 million in TRA payments, offset by $3 million in state tax refunds.

For the nine months ended September 30, 2024, there were $2 million in federal income tax payments, $52 million in state income tax payments, $8 million in state income tax refunds and no TRA payments.

Financial Covenants

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, for periods prior to the October 2024 amendments, in general, was applicable when the aggregate revolving borrowings and issued revolving letters of credit exceeded 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million were taken into account for purposes of determining whether a compliance period was in effect), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). As of September 30, 2024, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

See Note 9 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of September 30, 2024, Vistra has posted letters of credit in the amount of $95 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $585 million in the form of letters of credit, $81 million in the form of a surety bond and $3 million of cash as of September 30, 2024 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions

Certain of our contractual arrangements contain provisions that could result in an event of default if there were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions.

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.481 billion and zero, respectively, as of September 30, 2024.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross-default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

Under the Vistra Operations Senior Unsecured Indentures, the Vistra Operations Senior Secured Indenture and the Indenture governing the 7.233% Senior Secured Notes, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the 7.233% Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Commodity-Linked Facility and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.

The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC, TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and Vistra or any of their respective subsidiaries fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, in the case of Vistra Operations, and in a principal amount of at least $50 million, in the case of TXU Energy or any of the other Originators, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated.

The Repurchase Facility contains a cross-default provision. The cross-default provision applies, among other instances, if an event of default (or similar event) occurs under the Receivables Facility or the Vistra Operations Credit Facilities. If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated.

Under the Secured LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Secured LOC Facilities. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Secured LOC Facilities.

Under the Alternative LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Alternative LOC Facilities. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount exceeding the threshold above, may result in a termination of the Alternative LOC Facilities.

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes and the 6.000% Senior Secured Notes, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the respective notes and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

A default by Vistra Zero or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $100 million and 75% of Consolidated EBITDA may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $697 million as of September 30, 2024.

Under the UPAs, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the UPAs. Such a default would result in the payment obligations under the UPA of Vistra Vision Holdings and/or any guarantor thereunder becoming immediately due and payable.

Guarantees

See Note 14 to the Financial Statements for discussion of guarantees.

Commitments and Contingencies

See Note 14 to the Financial Statements for discussion of commitments and contingencies.

Changes in Accounting Standards

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

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