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 discussion below, as well as other portions of this quarterly report on Form 10-Q, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as may," "will," "should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and Part I, Item 1A "Risk Factors" in the Company's 2022 Form 10-K and any updates contained herein. Forward-looking statements reflect the information only as of the date on which they are made. The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information. If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements. This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the condensed consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q for the three months ended March 31, 2023. This discussion should be read in conjunction with those condensed consolidated financial statements and the related notes and is qualified by reference to them.

The following discussion and analysis of our financial condition and results of operations for the three months ended March 31, 2023 and 2022 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless otherwise indicated.

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 on the condensed consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2022 Form 10-K.

Business

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Operating Segments

Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 17 to the Financial Statements for further information concerning our reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Transaction Agreement

On March 6, 2023, Vistra Operations and Merger Sub entered into a Transaction Agreement with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra. The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's Board and Energy Harbor's board of directors. See Note 2 to the Financial Statements for more information concerning the Transaction Agreement.

Climate Change, Investments in Clean Energy and CO**2 Reductions

Environmental Regulations — We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. Environmental regulations could have a material impact on our business, such as certain corrective action measures that may be required under the CCR rule and the ELG rule (see Note 12 to the Financial Statements). However, such rules and the regulatory environment are continuing to evolve and change, and we cannot predict the ultimate effect that such changes may have on our business.

Emissions Reductions — Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 equivalent emissions by 2030 as compared to a 2010 baseline, with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary advancements in technology and supportive market constructs and public policy. In furtherance of Vistra's efforts to meet its net-zero target, Vistra expects to deploy multiple levers to transition the Company to operating with net-zero emissions.

Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green financial instruments to fund new or existing projects that support renewable energy and energy efficiency with alignment to our ESG strategy.

Solar Generation and Energy Storage Projects —

In September 2020, we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. Of this planned development in Texas, 158 MW of solar generation and the 260 MW battery ESS came online in 2022.
In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act.
In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site. The CPUC approved the resource adequacy and energy settlement contract in April 2022. This battery ESS is expected to enter commercial operations in the summer of 2023.

We will only invest in these growth projects if we are confident in the expected returns. See Note 3 to the Financial Statements for a summary of our solar and battery ESS projects.

CO**2 Reductions — In June 2022, September 2022 and January 2023, we retired the Zimmer coal-fueled generation facility, the Joppa generation facilities and the Edwards coal-fueled generation facility, respectively. See Note 4 to the Financial Statements for a summary of our planned generation retirements.

Comanche Peak Nuclear Plant License Renewal

In October 2022, we announced the submission of our application to the NRC for license renewal at our two-unit Comanche Peak Nuclear Plant. The current licenses for Units 1 and 2 extend into 2030 and 2033, respectively, and we are applying to renew the licenses into 2050 and 2053, respectively.

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 a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% CAMT on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months. The excise tax on stock repurchases is not expected to have a material impact on our financial statements. Vistra is not subject to the CAMT in the 2023 tax year since it only applies to corporations that have 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 for periods after the law takes effect and for estimating the TRA liability. See Note 1 for our accounting policy related to refundable and transferable PTCs and ITCs.

Macroeconomic Conditions

With forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods. As of March 31, 2023, we have hedged approximately 86% of our expected generation volumes on average for the balance of 2023 through 2025 (with approximately 99% hedged for the balance of 2023 and approximately 96% hedged for 2024).

The industry continues to experience supply chain constraints that have reduced the availability and increased the costs of certain fuels, such as coal, reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased the lead time to procure certain materials necessary to maintain 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 experienced throughout 2022 drove increases in interest rates, resulting in increased expected refinancing or borrowing costs, including project financing for our development projects.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows in 2021.

The weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021 after taking into account approximately $544 million in securitization proceeds Vistra received from ERCOT as further described in Note 1 to the Financial Statements. The primary drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs.

Vistra has taken various actions to improve its risk profile for future weather-driven volatility events, including investing in improvements to further harden its coal fuel handling capabilities and to further weatherize its ERCOT fleet for even colder temperatures and longer durations; carrying more backup generation into the peak seasons after accounting for weatherization investments and ERCOT market improvements implemented going forward; contracting for incremental gas storage to support its gas fleet; adding additional dual fuel capabilities at its gas steam units and increasing fuel oil inventory at its existing dual fuel sites; participating in processes with the PUCT and ERCOT for registration of gas infrastructure as critical resources with the transmission and distribution utilities and for enhanced winterization of both gas and power assets in the state; and engaging in processes to evaluate potential market reforms.

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program, which we initiated in the first quarter of 2019. See Note 13 to the Financial Statements for more information about our dividend program.

Share Repurchase Program

In October 2021, we announced that the Board had authorized a share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase Program became effective in October 2021. In August 2022 and March 2023, the Board authorized incremental amounts of $1.25 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $4.25 billion. We expect to complete repurchases under the current $4.25 billion Share Repurchase Program by the end of 2024.


	$4.25 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



Three Months Ended March 31, 2023	13,308,465	$	23.11	$	308	$	1,697
April 1, 2023 through May 4, 2023	5,555,721	24.04		133
January 1, 2023 through May 4, 2023	18,864,186	$	23.38	$	441	$	1,564

Since the Share Repurchase Program became effective in October 2021 through May 4, 2023, 116,665,098 shares of our common stock were repurchased for approximately $2.686 billion at an average price of $23.02 per share of common stock.

See Note 13 to the Financial Statements for more information concerning the Share Repurchase Program.

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. See Note 11 to the Financial Statements for details of our debt activity, including the April 2023 Amendment to the Vistra Operations Credit Agreement, and Note 10 to the Financial Statements for details of our accounts receivable financing.

Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments at March 31, 2023 were as follows:


	2023		2024
Nuclear/Renewable/Coal Generation:
Texas	98	%	97	%
Sunset	94	%	61	%
Gas Generation:
Texas	97	%	91	%
East	95	%	84	%
West	100	%	81	%

The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MMBtu/MWh) on realized pre-tax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of March 31, 2023.


	Balance 2023		2024
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	2	$	4
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	(2)	$	(3)
Gas Generation: $1.00/MWh increase in spark spread	$	2	$	4
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(4)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(4)	$	(15)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	9
East:
Gas Generation: $1.00/MWh increase in spark spread	$	3	$	9
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(8)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(2)	$	(10)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	2	$	10
West:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	1
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	(1)
Sunset:
Coal Generation: $2.50/MWh increase in power price	$	4	$	24
Coal Generation: $2.50/MWh decrease in power price	$	(2)	$	(21)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(3)	$	(13)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	3	$	13

RESULTS OF OPERATIONS

In the three months ended March 31, 2023, our operating segments delivered solid operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner. Our performance reflected the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business. As part of our comprehensive hedging strategy, we hedged longer-dated revenues and fuel costs to reduce risk and lock in value as forward power and gas curves moved up materially, and we believe this has positioned us to significantly benefit operating results in 2023 and beyond. In addition, we executed on our share repurchase strategy.

Consolidated Financial Results — Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022


	Three Months Ended March 31,					Favorable (Unfavorable) $ Change
		2023			2022
Operating revenues			$	4,425		$	3,125	$	1,300
Fuel, purchased power costs and delivery fees			(2,170)			(2,279)		109
Operating costs			(421)			(416)		(5)
Depreciation and amortization			(366)			(430)		64
Selling, general and administrative expenses			(288)			(288)		—

Impairment of long-lived assets			(49)			—		(49)
Operating income (loss)			1,131			(288)		1,419
Other income			20			5		15
Other deductions			(3)			(4)		1
Interest expense and related charges			(207)			(7)		(200)
Impacts of Tax Receivable Agreement			(65)			(81)		16

Income (loss) before income taxes			876			(375)		1,251
Income tax (expense) benefit			(178)			91		(269)
Net income (loss)			$	698		$	(284)	$	982


	Three Months Ended March 31, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,350	$	1,353	$	1,809	$	231	$	828	$	—	$	(2,146)	$	4,425
Fuel, purchased power costs and delivery fees	(2,690)		(395)		(820)		(148)		(262)		(1)		2,146		(2,170)
Operating costs	(28)		(228)		(65)		(15)		(65)		(20)		—		(421)
Depreciation and amortization	(29)		(130)		(161)		(15)		(14)		—		(17)		(366)
Selling, general and administrative expenses	(191)		(31)		(19)		(6)		(13)		(8)		(20)		(288)

Impairment of long-lived assets	—		—		—		—		(49)		—		—		(49)
Operating income (loss)	(588)		569		744		47		425		(29)		(37)		1,131
Other income	—		12		1		1		1		3		2		20
Other deductions	—		(1)		—		—		(1)		—		(1)		(3)
Interest expense and related charges	(7)		4		—		4		(1)		(1)		(206)		(207)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(65)		(65)

Income (loss) before income taxes	(595)		584		745		52		424		(27)		(307)		876
Income tax expense	—		—		—		—		—		—		(178)		(178)
Net income (loss)	$	(595)	$	584	$	745	$	52	$	424	$	(27)	$	(485)	$	698


	Three Months Ended March 31, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	1,825	$	(1,095)	$	955	$	72	$	(118)	$	85	$	1,401	$	3,125
Fuel, purchased power costs and delivery fees	864		(526)		(828)		(73)		(195)		(120)		(1,401)		(2,279)
Operating costs	(33)		(201)		(57)		(12)		(62)		(50)		(1)		(416)
Depreciation and amortization	(36)		(123)		(179)		(42)		(16)		(17)		(17)		(430)
Selling, general and administrative expenses	(188)		(32)		(17)		(6)		(9)		(11)		(25)		(288)


Operating income (loss)	2,432		(1,977)		(126)		(61)		(400)		(113)		(43)		(288)
Other income	—		1		—		—		—		2		2		5
Other deductions	(3)		(1)		—		—		—		—		—		(4)
Interest expense and related charges	(1)		5		(2)		—		—		(1)		(8)		(7)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(81)		(81)

Income (loss) before income taxes	2,428		(1,972)		(128)		(61)		(400)		(112)		(130)		(375)
Income tax benefit	—		—		—		—		—		—		91		91
Net income (loss)	$	2,428	$	(1,972)	$	(128)	$	(61)	$	(400)	$	(112)	$	(39)	$	(284)

Operating income (loss) increased $1.419 billion to operating income of $1.131 billion in the three months ended March 31, 2023 compared to the three months ended March 31, 2022. Results for the three months ended March 31, 2023 were favorably impacted by $1.085 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 three months ended March 31, 2023 compared to $360 million in pre-tax unrealized mark-to-market losses on commodity derivative positions due to power and natural gas forward market curves moving up in the three months ended March 31, 2022. Included within these unrealized mark-to-market changes are pre-tax net unrealized gains of $153 million recorded in the three months ended March 31, 2023 due to the second quarter of 2022 discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

Interest expense and related charges increased $200 million to $207 million in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 driven by unrealized mark-to-market losses on interest rate swaps of $41 million in 2023 compared to $126 million in gains in 2022 due to less volatility in interest rates in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 and an increase in interest paid/accrued of $30 million driven by higher effective interest rates in 2023. See Note 18 to the Financial Statements.

For the three months ended March 31, 2023 and 2022, the impacts of the TRA resulted in expense of $65 million and $81 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.

For the three months ended March 31, 2023, income tax expense totaled $178 million and the effective tax rate was 20.3%. For the three months ended March 31, 2022, income tax benefit totaled $91 million, and the effective tax rate was 24.3%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Discussion of Adjusted EBITDA

Non-GAAP Measures — 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 with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. 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 our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our segments for the period presented. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts of mark-to-market changes on derivatives, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other nonrecurring or unusual items.

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.

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).

Adjusted EBITDA — Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022


	Three Months Ended March 31,					Favorable (Unfavorable) $ Change
		2023			2022
Net income (loss)			$	698		$	(284)	$	982
Income tax expense (benefit)			178			(91)		269
Interest expense and related charges (a)			207			7		200
Depreciation and amortization (b)			389			452		(63)
EBITDA before Adjustments			1,472			84		1,388
Unrealized net (gain) loss resulting from commodity hedging transactions (c)			(1,085)			360		(1,445)
Generation plant retirement expenses			1			6		(5)
Fresh start/purchase accounting impacts			3			—		3
Impacts of Tax Receivable Agreement			65			81		(16)

Non-cash compensation expenses			22			17		5
Transition and merger expenses			1			17		(16)
Impairment of long-lived assets			49			—		49


PJM capacity performance default impacts (d)			20			—		20
Winter Storm Uri impacts (e)			(33)			(54)		21
Other, net			(2)			30		(32)
Adjusted EBITDA			$	513		$	541	$	(28)

(a)Includes unrealized mark-to-market net losses on interest rate swaps of $41 million for the three months ended March 31, 2023 and unrealized mark-to-market net gains on interest rate swaps of $126 million for the three months ended March 31, 2022.

(b)Includes nuclear fuel amortization in the Texas segment of $23 million and $22 million for the three months ended March 31, 2023 and 2022, respectively.

(c)Net pre-tax unrealized mark-to-market gains on commodity hedging transactions were driven by a decrease in power and natural gas price curves during the three months ended March 31, 2023. Additionally, we recorded pre-tax net unrealized gains of $153 million in the three months ended March 31, 2023 due to the second quarter of 2022 discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

(d)Represents initial estimate of anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott, which amounts are expected to be withheld by PJM from our net bonus position during 2023.

(e)For the three months ended March 31, 2023, includes reductions to Adjusted EBITDA reflecting bill credit applications of $34 million. For the three months ended March 31, 2022, includes reductions to Adjusted EBITDA reflecting default uplift charges of $42 million, attributable to ERCOT receiving payments that reduced the market wide default balance, and bill credit applications of $12 million. In 2021, an adjustment for future bill credits was recorded related to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. These amounts reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance.


	Three Months Ended March 31, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	(595)	$	584	$	745	$	52	$	424	$	(27)	$	(485)	$	698
Income tax expense	—		—		—		—		—		—		178		178
Interest expense and related charges (a)	7		(4)		—		(4)		1		1		206		207
Depreciation and amortization (b)	29		153		161		15		14		—		17		389
EBITDA before Adjustments	(559)		733		906		63		439		(26)		(84)		1,472
Unrealized net (gain) loss resulting from hedging transactions	559		(346)		(923)		(18)		(340)		(17)		—		(1,085)
Generation plant retirement expenses	—		—		—		—		—		—		1		1
Fresh start/purchase accounting impacts	1		(1)		2		—		1		—		—		3
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		65		65

Non-cash compensation expenses	—		—		—		—		—		—		22		22
Transition and merger expenses	(2)		—		—		—		1		—		2		1
Impairment of long-lived assets	—		—		—		—		49		—		—		49


PJM capacity performance default impacts (c)	—		—		14		—		6		—		—		20
Winter Storm Uri impacts (d)	(34)		1		—		—		—		—		—		(33)
Other, net	6		(4)		2		1		8		2		(17)		(2)
Adjusted EBITDA	$	(29)	$	383	$	1	$	46	$	164	$	(41)	$	(11)	$	513

(a)Includes $41 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $23 million in the Texas segment.

(c)Represents initial estimate of anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott, which amounts are expected to be withheld by PJM from our net bonus position during 2023.

(d)Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. We estimate remaining bill credit amounts to be applied in future periods are for the remainder of 2023 (approximately $21 million), 2024 (approximately $9 million) and 2025 (approximately $25 million).


	Three Months Ended March 31, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	2,428	$	(1,972)	$	(128)	$	(61)	$	(400)	$	(112)	$	(39)	$	(284)
Income tax benefit	—		—		—		—		—		—		(91)		(91)
Interest expense and related charges (a)	1		(5)		2		—		1		—		8		7
Depreciation and amortization (b)	36		145		179		42		16		17		17		452
EBITDA before Adjustments	2,465		(1,832)		53		(19)		(383)		(95)		(105)		84
Unrealized net (gain) loss resulting from hedging transactions	(2,306)		2,031		93		44		413		85		—		360
Generation plant retirement expenses	—		—		—		—		4		2		—		6

Impacts of Tax Receivable Agreement	—		—		—		—		—		—		81		81

Non-cash compensation expenses	—		—		—		—		—		—		17		17
Transition and merger expenses	6		—		1		—		—		—		10		17



Winter Storm Uri impacts (c)	(12)		(42)		—		—		—		—		—		(54)
Other, net	10		14		1		—		10		8		(13)		30
Adjusted EBITDA	$	163	$	171	$	148	$	25	$	44	$	—	$	(10)	$	541

(a)Includes $126 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $22 million in Texas segment.

(c)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.

Retail Segment — Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022


	Three Months Ended March 31,						Favorable (Unfavorable) Change
		2023				2022
Operating revenues:
Revenues in ERCOT			$	1,723			$	1,551		$	172
Revenues in Northeast/Midwest			487				643			(156)
Amortization expense			(1)				—			(1)
Unrealized net gains (losses) on hedging activities (a)			141				(369)			510
Total operating revenues			2,350				1,825			525
Fuel, purchased power costs and delivery fees:
Purchases from affiliates			(1,465)				(1,271)			(194)
Unrealized net gains (losses) on hedging activities with affiliates (b)			(680)				2,673			(3,353)
Unrealized net gains (losses) on hedging activities			(19)				2			(21)
Delivery fees			(497)				(511)			14
Other costs			(29)				(29)			—
Total fuel, purchased power costs and delivery fees			(2,690)				864			(3,554)










Net income (loss)			$	(595)			$	2,428		$	(3,023)













Adjusted EBITDA			$	(29)			$	163		$	(192)

Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT			14,982				14,213			769
Sales volumes in Northeast/Midwest			5,830				9,106			(3,276)
Total retail electricity sales volumes			20,812				23,319			(2,507)
Weather (North Texas average) - percent of normal (c):

Heating degree days			82.8		%		118.1		%

(a)Includes pre-tax unrealized net gains of $153 million for the three months ended March 31, 2023 recognized due to the second quarter of 2022 discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

(b)Includes unrealized net gains/(losses) from mark-to-market valuations of commodity positions with the Texas, East and Sunset segments.

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended March 31, 2023 compared to the three months ended March 31, 2022.


	Three Months Ended March 31, 2023 Compared to 2022
Lower margins driven by seasonality of power costs	$	(116)
Winter Storm Uri impact, including bill credits	(21)
Lower margins due to mild weather in 2023	(43)
Other primarily driven by higher bad debt expense due to higher revenues in ERCOT	(12)
Change in Adjusted EBITDA	$	(192)
Unfavorable impact of unrealized net losses on hedging activities	(2,865)
Bill credits and other costs related to Winter Storm Uri	22
Decrease in depreciation and amortization expenses	7
Change in other expenses	5
Change in Net income	$	(3,023)

Generation — Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022


	Three Months Ended March 31,
	Texas						East						West						Sunset
	2023			2022			2023			2022			2023			2022			2023			2022
Operating revenues:
Electricity sales	$	86		$	234		$	388		$	644		$	213		$	116		$	241		$	129
Capacity revenue from ISO/RTO	—			—			8			(6)			—			—			19			33
Sales to affiliates	897			644			471			516			6			2			92			108
Rolloff of unrealized net gains (losses) representing positions settled in the current period	175			251			357			37			50			(4)			(14)			43
Unrealized net gains (losses) on hedging activities	8			(213)			192			272			(36)			(43)			388			(293)
Unrealized net gains (losses) on hedging activities with affiliates	185			(2,011)			394			(509)			(2)			1			103			(136)
Other revenues	2			—			(1)			1			—			—			(1)			(2)
Operating revenues	1,353			(1,095)			1,809			955			231			72			828			(118)
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(322)			(410)			(786)			(929)			(153)			(74)			(123)			(166)
Fuel for generation facilities and purchased power costs from affiliates	—			—			—			—			—			—			—			(1)
Unrealized gains (losses) from hedging activities	(22)			(55)			(20)			106			6			3			(137)			(29)
Unrealized gains (losses) from hedging activities with affiliates	—			(3)			—			1			—			—			—			2
Ancillary and other costs	(51)			(58)			(14)			(6)			(1)			(2)			(2)			(1)
Fuel, purchased power costs and delivery fees	(395)			(526)			(820)			(828)			(148)			(73)			(262)			(195)










Net income (loss)	$	584		$	(1,972)		$	745		$	(128)		$	52		$	(61)		$	424		$	(400)














Adjusted EBITDA	$	383		$	171		$	1		$	148		$	46		$	25		$	164		$	44
Production volumes (GWh):
Natural gas facilities	6,225			5,901			14,585			14,336			1,543			1,196
Lignite and coal facilities	4,971			6,370															3,516			5,952
Nuclear facilities	5,227			5,223
Solar facilities	154			166
Capacity factors:
CCGT facilities	35.0		%	34.1		%	62.2		%	61.5		%	70.1		%	53.9		%
Lignite and coal facilities	59.8		%	76.6		%													35.6		%	60.2		%
Nuclear facilities	100.9		%	100.8		%
Weather - percent of normal (a):

Heating degree days	81.1		%	133.5		%	84.4		%	100.4		%	148.7		%	93.1		%	86.9		%	104.9		%

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


	Three Months Ended March 31,							Three Months Ended March 31,
	2023			2022				2023		2022
Market pricing						Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	21.98		$	36.91	PJM West Hub		$	36.35	$	58.10
			AEP Dayton Hub	$	33.65	$	50.83
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.68		$	4.60	NYISO Zone C		$	30.96	$	72.41
			Massachusetts Hub	$	51.98	$	114.92
Average natural gas price (a):						Indiana Hub		$	35.52	$	55.92
TetcoM3 ($/MMBtu)	$	2.93		$	6.73	Northern Illinois Hub		$	29.58	$	44.45
Algonquin Citygates ($/MMBtu)	$	5.13		$	13.67	CAISO NP15		$	100.31	$	50.43

(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 changes in net income (loss) and Adjusted EBITDA for the three months ended March 31, 2023 compared to the three months ended March 31, 2022.


	Three Months Ended March 31, 2023 Compared to 2022
	Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	$	238	$	(137)	$	22	$	131

Unfavorable change in other operating costs	(28)		(8)		(3)		(7)
Favorable/(unfavorable) change in selling, general and administrative expenses	2		(2)		2		(5)
Other	—		—		—		1
Change in Adjusted EBITDA	$	212	$	(147)	$	21	$	120
Favorable/(unfavorable) change in depreciation and amortization	(8)		18		27		2
Change in unrealized net gains on hedging activities	2,377		1,016		62		753
Impairment of long-lived assets	—		—		—		(49)
Generation plant retirement expenses	—		—		—		4
Fresh start/purchase accounting impacts	1		(2)		—		(1)


PJM capacity performance default impacts	—		(14)		—		(6)
Winter Storm Uri impact (ERCOT default uplift)	(43)		—		—		—
Other (including interest expenses)	17		2		3		1
Change in Net income (loss)	$	2,556	$	873	$	113	$	824

The favorable changes in Texas, East, West and Sunset segment results were primarily driven by unrealized hedging gains due to decreases in forward power prices in the three months ended March 31, 2023 compared to unrealized hedging losses due to increases in power prices in the three months ended March 31, 2022.

The change in Texas segment results was also driven by higher revenue net of fuel in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due to strong generation performance during periods of higher pricing and the effectiveness of our comprehensive hedging strategy.

The change in East segment results was also driven by lower revenue net of fuel in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices and lower capacity revenues.

The change in West segment results was driven by higher revenue net of fuel in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due to higher generation volumes and margins.

The change in Sunset segment results was also driven by higher revenue net of fuel in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due to the effectiveness of our comprehensive hedging strategy. A $49 million impairment of assets related to our Kincaid generation facility was recognized in the three months ended March 31, 2023. See Note 18 to the Financial Statements for more information concerning the impairment.

Asset Closure Segment — Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022


	Three Months Ended March 31,					Favorable (Unfavorable) Change
		2023			2022
Operating revenues			$	—		$	85	$	(85)
Fuel, purchased power costs and delivery fees			(1)			(120)		119
Operating costs			$	(20)		$	(50)	$	30
Depreciation and amortization			—			(17)		17
Selling, general and administrative expenses			(8)			(11)		3


Operating loss			(29)			(113)		84
Other income			3			2		1

Interest expense and related charges			(1)			(1)		—

Income (loss) before income taxes			(27)			(112)		85

Net loss			$	(27)		$	(112)	$	85











Adjusted EBITDA			$	(41)		$	—	$	(41)
Production volumes (GWh)			—			3,896		(3,896)

For the three months ended March 31, 2022, results and volumes for the Asset Closure segment include those from Edwards generation plant that we retired on January 1, 2023, and include unrealized hedging losses of $33 million related to coal and power derivatives. Operating costs for the three months ended March 31, 2023 and 2022 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The decrease in net losses in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 is driven by the retirements of the Zimmer, Joppa and Edwards generation plants on June 1 ,2022, September 1, 2022 and January 1, 2023, respectively.

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

The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2023 and 2022. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.085 billion in unrealized net gains and $360 million in unrealized net losses for the three months ended March 31, 2023 and 2022, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


	Three Months Ended March 31,
	2023		2022
Commodity contract net liability at beginning of period	$	(3,148)	$	(866)
Settlements/termination of positions (a)	711		375
Changes in fair value of positions in the portfolio (b)	374		(735)

Other activity (c)	(36)		(96)
Commodity contract net liability at end of period	$	(2,099)	$	(1,322)

(a)Represents reversals of previously recognized unrealized gains/(losses) upon settlement/termination (offsets realized gains and 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)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.

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at March 31, 2023, scheduled by the source of fair value and contractual settlement dates of the underlying positions.


	Maturity dates of unrealized commodity contract net liability at March 31, 2023
Source of fair value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	$	(862)	$	(305)	$	2	$	—	$	(1,165)
Prices provided by other external sources	233		58		—		—		291
Prices based on models	(162)		(650)		(232)		(181)		(1,225)
Total	$	(791)	$	(897)	$	(230)	$	(181)	$	(2,099)

FINANCIAL CONDITION

Operating Cash Flows

Cash provided by operating activities totaled $1.435 billion and $591 million for the three months ended March 31, 2023 and 2022, respectively. The favorable change of $844 million was primarily driven by a decrease in net margin deposits of $1.227 billion in the first quarter of 2023 as compared to $210 million in the first quarter of 2022 related to commodity contracts which support our comprehensive hedging strategy.

Depreciation and amortization expense 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 $111 million and $112 million for the three months ended March 31, 2023 and 2022, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other condensed consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.

Investing Cash Flows

Cash used in investing activities totaled $513 million and $480 million for the three months ended March 31, 2023 and 2022, respectively. The increase of $33 million was driven by a $111 million increase in capital expenditures due primarily to continued development of our solar and energy storage generation facilities (see Note 3 to the Financial Statements), partially offset by $83 million in lower net purchases of environmental allowances.


	Three Months Ended March 31,				Increase (Decrease)
	2023		2022
Capital expenditures, including LTSA prepayments	$	(202)	$	(153)	$	(49)
Nuclear fuel purchases	(64)		(103)		39
Growth and development expenditures	(218)		(117)		(101)
Total capital expenditures	(484)		(373)		(111)
Net sales (purchases) of environmental allowances	(26)		(109)		83
Net sales of (investments in) nuclear decommissioning trust fund securities	(6)		(5)		(1)
Insurance proceeds related to capital activity	3		1		2
Proceeds from sales of assets	2		3		(1)
Other investing activity	(2)		3		(5)
Cash used in investing activities	$	(513)	$	(480)	$	(33)

Financing Cash Flows

Cash used in financing activities totaled $874 million and $413 million for the three months ended March 31, 2023 and 2022, respectively. The $461 million increase in cash used was primarily driven by $650 million of short-term debt repayments in the three months ended March 31, 2023, partially offset by lower share repurchases.


	Three Months Ended March 31,				Increase (Decrease)
	2023		2022
Share repurchases	$	(301)	$	(710)	$	409

Net long-term borrowings (repayments), including the forward capacity agreements	(7)		(132)		125
Net short-term borrowings (repayments)	(650)		—		(650)
Net borrowings (repayments) under the accounts receivable financing facilities	175		500		(325)
Dividends paid to common stockholders	(77)		(77)		—

Other financing activity	(14)		6		(20)
Cash used in financing activities	$	(874)	$	(413)	$	(461)

Debt Activity

The maturities of our long-term debt are relatively modest until 2024. See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the three months ended March 31, 2023:


	March 31, 2023		December 31, 2022		Change
Cash and cash equivalents	$	518	$	455	$	63
Vistra Operations Credit Facilities — Revolving Credit Facility	1,992		1,236		756
Vistra Operations — Commodity-Linked Facility (a)	169		808		(639)
Total available liquidity (b)(c)	$	2,679	$	2,499	$	180

____________

(a)As of both March 31, 2023 and December 31, 2022, the borrowing bases are less than the facility limit of $1.35 billion. As of March 31, 2023, available capacity reflects the borrowing base of $169 million and no cash borrowings. As of December 31, 2022, available capacity reflects the borrowing base of $1.208 billion less $400 million in cash borrowings. The reduction in the borrowing base is due to a decrease in commodity prices and would increase in size in a rising commodity price environment in accordance with the terms of the Commodity-Linked Facility.

(b)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 10 to the Financial Statements for detail on our accounts receivable financing.

(c)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities. See Note 11 to the Financial Statements for detail on our Secured LOC Facilities.

The $180 million increase in available liquidity for the three months ended March 31, 2023 was primarily driven by cash provided by operations, a $506 million decrease in letters of credit outstanding under the Revolving Credit Facility and a $175 million decrease in net cash borrowings under the accounts receivable financing facilities, partially offset by a $639 million decrease in availability under the Commodity-Linked Facility, primarily due to a reduction of the borrowing base of $1.039 billion due to a decrease in commodity prices and partially offset by the repayment of $400 million in borrowings under the facility.

We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

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 and other forms of credit support to satisfy such collateral posting obligations. See Note 11 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

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.

At March 31, 2023, we received or posted cash and letters of credit for commodity hedging activities as follows:

$1.919 billion in cash has been posted with counterparties as compared to $3.137 billion posted at December 31, 2022;
$48 million in cash has been received from counterparties as compared to $39 million received at December 31, 2022;
$1.826 billion in letters of credit have been posted with counterparties as compared to $2.314 billion posted at December 31, 2022; and
$122 million in letters of credit have been received from counterparties as compared to $74 million received at December 31, 2022.

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 do not expect to make federal income tax payments due to Vistra's NOL carryforwards. We expect to make approximately $29 million in state income tax payments, offset by $6 million in state tax refunds, and $9 million in TRA payments in the next 12 months.

For the three months ended March 31, 2023, there were no federal income tax payments, $1 million in state income tax payments, $7 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, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is 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, 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, not to exceed 5.50 to 1.00). As of March 31, 2023, we were in compliance with these financial covenants.

See Note 11 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, at March 31, 2023, Vistra has posted letters of credit in the amount of $87 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 $536 million in the form of letters of credit, $30 million in the form of a surety bond and $2 million of cash at March 31, 2023 (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 $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.507 billion at March 31, 2023.

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 and the Vistra Operations Senior Secured Indenture, 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 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 and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy or any of the other Originators, in a principal amount of at least $50 million, 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 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 Commodity-Linked Facility, 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 Commodity-Linked Facility.

Guarantees

See Note 12 to the Financial Statements for discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 12 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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