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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 and nine months ended September 30, 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 and nine months ended September 30, 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 18 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 13 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 entered commercial operations in June 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 September 30, 2023, we have hedged approximately 90% 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 97% hedged for 2024).

The industry continues to experience supply chain constraints that have reduced the availability and increased the costs of certain fuels, 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 and refinancing expected in connection with debt due in 2024.

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 14 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 RepurchasedAverage Price Paid Per ShareAmount Paid for Shares RepurchasedAmount Available for Additional Repurchases at the End of the Period
Three Months Ended March 31, 202313,308,465$23.11$308
Three Months Ended June 30, 202310,144,89124.39247
Three Months Ended September 30, 202310,550,30730.36320
Nine Months Ended September 30, 202334,003,663$25.74$875$1,130
October 1, 2023 through November 2, 20234,547,26432.27147
January 1, 2023 through November 2, 202338,550,927$26.51$1,022$983

Since the Share Repurchase Program became effective in October 2021 through November 2, 2023, 136,351,839 shares of our common stock were repurchased for approximately $3.267 billion at an average price of $23.96 per share of common stock.

See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program.

Collateral Financing Agreement With Affiliate

On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust will be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.

Under the Facility Agreement, Vistra Operations will have the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% senior secured notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time.

The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase.

See Note 11 for additional details of the collateral financing agreement with affiliate.

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 12 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 as of September 30, 2023 were as follows:

Balance of 20232024
Nuclear/Renewable/Coal Generation:
Texas99%98%
Sunset100%89%
Gas Generation:
Texas98%93%
East100%95%
West100%100%

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 September 30, 2023.

Balance of 20232024
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price$—$3
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price$—$(2)
Gas Generation: $1.00/MWh increase in spark spread$—$4
Gas Generation: $1.00/MWh decrease in spark spread$—$(3)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$(2)$(10)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$—$9
East:
Gas Generation: $1.00/MWh increase in spark spread$—$4
Gas Generation: $1.00/MWh decrease in spark spread$—$(2)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$1$(3)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$(1)$3
West:
Gas Generation: $1.00/MWh increase in spark spread$—$—
Gas Generation: $1.00/MWh decrease in spark spread$—$—
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$—$2
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$—$(2)
Sunset:
Coal Generation: $2.50/MWh increase in power price$—$6
Coal Generation: $2.50/MWh decrease in power price$1$(7)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$—$(1)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$—$1

RESULTS OF OPERATIONS

In the three and nine months ended September 30, 2023, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner. Our performance reflected strong plant operating performance, increased demand due to hot weather in Texas and the effectiveness of our comprehensive hedging strategy and the value we were able to lock in as forward power and gas curves moved up materially in 2022. We believe remaining long-dated hedges position us to significantly benefit operating results through the remainder of 2023 and beyond, supporting the continued execution of our share repurchase and overall capital allocation strategy.

Consolidated Financial Results — Three and Nine Months Ended September 30, 2023 Compared to Three and Nine Months Ended September 30, 2022

Three Months Ended September 30,Favorable (Unfavorable) $ ChangeNine Months Ended September 30,Favorable (Unfavorable) $ Change
2023202220232022
Operating revenues$4,086$5,146$(1,060)$11,701$9,859$1,842
Fuel, purchased power costs and delivery fees(2,109)(3,139)1,030(5,754)(7,580)1,826
Operating costs(411)(400)(11)(1,277)(1,250)(27)
Depreciation and amortization(375)(390)15(1,109)(1,214)105
Selling, general and administrative expenses(357)(323)(34)(953)(894)(59)
Impairment of long-lived assets———(49)—(49)
Operating income (loss)834894(60)2,559(1,079)3,638
Other income3210221748886
Other deductions(3)(5)2(9)(18)9
Interest expense and related charges(143)(71)(72)(450)(186)(264)
Impacts of Tax Receivable Agreement(49)86(135)(128)(29)(99)
Income (loss) before income taxes671914(243)2,146(1,224)3,370
Income tax (expense) benefit(169)(236)67(470)262(732)
Net income (loss)$502$678$(176)$1,676$(962)$2,638
Three Months Ended September 30, 2023
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
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)24742929256(42)(23)(62)834
Other income—4—8—71332
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 taxes24543829264(44)(17)(244)671
Income tax expense——————(169)(169)
Net income (loss)$245$438$29$264$(44)$(17)$(413)$502
Three Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Operating revenues$3,258$3,627$1,126$236$253$95$(3,449)$5,146
Fuel, purchased power costs and delivery fees(4,161)(1,119)(983)(155)(132)(39)3,450(3,139)
Operating costs(43)(193)(58)(10)(64)(32)—(400)
Depreciation and amortization(36)(135)(187)4(17)(1)(18)(390)
Selling, general and administrative expenses(238)(33)(18)(5)(9)(12)(8)(323)
Operating income (loss)(1,220)2,147(120)703111(25)894
Other income211——6—10
Other deductions(5)(1)——1——(5)
Interest expense and related charges(4)9—2(1)(1)(76)(71)
Impacts of Tax Receivable Agreement——————8686
Income (loss) before income taxes(1,227)2,156(119)723116(15)914
Income tax expense——————(236)(236)
Net income (loss)$(1,227)$2,156$(119)$72$31$16$(251)$678

Operating income decreased $60 million to operating income of $834 million in the three months ended September 30, 2023 compared to the three months ended September 30, 2022. This decrease is primarily related to a $603 million change in unrealized mark-to-market as results for the three months ended September 30, 2023 were unfavorably impacted by $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 compared to $320 million 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 September 30, 2022. The unfavorable variance related to unrealized mark-to-market is offset by improved operating performance in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 driven by strong plant operating performance and higher energy margins reflecting the effectiveness of our comprehensive hedging strategy driving higher realized energy margins. Additionally, revenue net of fuel was higher in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices in the third quarter of 2022.

Interest expense and related charges increased $72 million to $143 million in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 driven by unrealized mark-to-market gains on interest rate swaps of $43 million in 2023 compared to $90 million in 2022 due to less volatility in interest rates in the three months ended September 30, 2023 compared to the three months ended September 30, 2022, (b) $12 million of previously capitalized commitment fees related to the Commitment Letter that were reclassified to interest expense and related charges in the three months ended September 30, 2022 (see Note 2 to the Financial Statements) and (c) an increase in interest paid/accrued of $5 million driven by higher effective interest rates in 2023. See Note 19 to the Financial Statements.

For the three months ended September 30, 2023 and 2022, the impacts of the TRA resulted in expense of $49 million and income of $86 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.

For the three months ended September 30, 2023, income tax expense totaled $169 million and the effective tax rate was 25.2%. For the three months ended September 30, 2022, income tax expense totaled $236 million, and the effective tax rate was 25.8%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Nine Months Ended September 30, 2023
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
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)4813501,048456447(78)(145)2,559
Other income—32217110517174
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 taxes4623961,05048144223(708)2,146
Income tax expense——(1)———(469)(470)
Net income (loss)$462$396$1,049$481$442$23$(1,177)$1,676
Nine Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Operating revenues$6,876$1,909$2,400$387$55$297$(2,065)$9,859
Fuel, purchased power costs and delivery fees(3,913)(2,342)(2,524)(279)(313)(275)2,066(7,580)
Operating costs(111)(602)(189)(32)(191)(125)—(1,250)
Depreciation and amortization(109)(404)(545)(26)(49)(29)(52)(1,214)
Selling, general and administrative expenses(622)(99)(50)(17)(26)(33)(47)(894)
Operating income (loss)2,121(1,538)(908)33(524)(165)(98)(1,079)
Other income2651——14688
Other deductions(16)(2)——1(1)—(18)
Interest expense and related charges(8)20(3)3(2)(2)(194)(186)
Impacts of Tax Receivable Agreement——————(29)(29)
Income (loss) before income taxes2,099(1,455)(910)36(525)(154)(315)(1,224)
Income tax benefit——————262262
Net income (loss)$2,099$(1,455)$(910)$36$(525)$(154)$(53)$(962)

Operating income increased $3.638 billion to operating income of $2.559 billion in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022. Results for the nine months ended September 30, 2023 were favorably impacted by $855 million in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the nine months ended September 30, 2023 compared to $2.027 billion in pre-tax unrealized mark-to-market losses on commodity derivative positions due to power and natural gas forward market curves moving up materially in the nine months ended September 30, 2022. Additionally, results in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 were favorably impacted by strong plant operating performance and higher energy margins reflecting the effectiveness of our comprehensive hedging strategy driving higher realized energy margins.

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. For the nine months ended September 30, 2022, other income totaled $88 million driven by insurance proceeds of $63 million which primarily consists of business interruption claim proceeds. See Note 19 to the Financial Statements.

Interest expense and related charges increased $264 million to $450 million in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 driven by (a) unrealized mark-to-market gains on interest rate swaps of $65 million in 2023 compared to $261 million in 2022 due to less volatility in interest rates in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, (b) an increase in interest paid/accrued of $45 million driven by higher effective interest rates in 2023 and (c) $21 million of previously capitalized commitment fees related to the Commitment Letter that were reclassified to interest expense and related charges in the nine months ended September 30, 2022 (see Note 2 to the Financial Statements). See Note 19 to the Financial Statements.

For the nine months ended September 30, 2023 and 2022, the impacts of the TRA resulted in expense of $128 million and $29 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.

For the nine months ended September 30, 2023, income tax expense totaled $470 million and the effective tax rate was 21.9%. For the nine months ended September 30, 2022, income tax benefit totaled $262 million, and the effective tax rate was 21.4%. 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 depreciable 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 and Nine Months Ended September 30, 2023 Compared to Three and Nine Months Ended September 30, 2022

Three Months Ended September 30,Favorable (Unfavorable) $ ChangeNine Months Ended September 30,Favorable (Unfavorable) $ Change
2023202220232022
Net income (loss)$502$678$(176)$1,676$(962)$2,638
Income tax expense (benefit)169236(67)470(262)732
Interest expense and related charges (a)1437172450186264
Depreciation and amortization (b)401413(12)1,1771,277(100)
EBITDA before Adjustments1,2151,398(183)3,7732393,534
Unrealized net (gain) loss resulting from commodity hedging transactions (c)283(320)603(855)2,027(2,882)
Impacts of Tax Receivable Agreement49(86)1351282999
Non-cash compensation expenses21147634815
Transition and merger expenses22(2)24391821
Impairment of long-lived assets———49—49
PJM capacity performance default impacts (d)1—19—9
Winter Storm Uri impacts (e)(7)(31)24(44)(147)103
Other, net58(3)644(38)
Adjusted EBITDA$1,589$981$608$3,168$2,258$910

(a)Includes unrealized mark-to-market net gains on interest rate swaps of $43 million and $65 million for the three and nine months ended September 30, 2023, respectively, and unrealized mark-to-market net gains on interest rate swaps of $90 million and $261 million for the three and nine months ended September 30, 2022, respectively.

(b)Includes nuclear fuel amortization in the Texas segment of $26 million and $23 million for the three months ended September 30, 2023 and 2022, respectively, and $68 million and $63 million for the nine months ended September 30, 2023 and 2022, respectively.

(c)Net pre-tax unrealized mark-to-market losses on commodity hedging transactions were driven by an increase in Texas forward power curves during the three months ended September 30, 2023. Net pre-tax unrealized mark-to-market gains on commodity hedging transactions were driven by a decrease in power and natural gas forward market curves during the three months ended September 30, 2022. Net pre-tax unrealized mark-to-market gains on commodity hedging transactions were driven by a decrease in power and natural gas forward market curves during the nine months ended September 30, 2023. Net pre-tax unrealized mark-to-market losses on commodity hedging transactions were driven by an increase in power and natural gas forward market curves during the nine months ended September 30, 2022.

(d)For the three and nine months ended September 30, 2023, 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.

(e)For the three and nine months ended September 30, 2023, includes reductions to Adjusted EBITDA reflecting bill credit applications of $7 million and $46 million, respectively. For the three and nine months ended September 30, 2022, includes reductions to Adjusted EBITDA reflecting default uplift charges of zero and $56 million, respectively, attributable to ERCOT receiving payments that reduced the market wide default balance, and bill credit applications of $32 million and $98 million, respectively. 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 September 30, 2023
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$245$438$29$264$(44)$(17)$(413)$502
Income tax expense——————169169
Interest expense and related charges (a)2(5)———1145143
Depreciation and amortization (b)261581612216—18401
EBITDA before Adjustments273591190286(28)(16)(81)1,215
Unrealized net (gain) loss resulting from hedging transactions(97)356125(203)110(8)—283
Impacts of Tax Receivable Agreement——————4949
Non-cash compensation expenses——————2121
Transition and merger expenses——————2222
PJM capacity performance default impacts (c)——(3)—4——1
Winter Storm Uri impacts (d)(8)1—————(7)
Other, net523416—(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 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)Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri.

Three Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$(1,227)$2,156$(119)$72$31$16$(251)$678
Income tax expense——————236236
Interest expense and related charges (a)4(9)—(2)117671
Depreciation and amortization (b)36158187(4)17118413
EBITDA before Adjustments(1,187)2,30568664918791,398
Unrealized net (gain) loss resulting from hedging transactions1,203(1,436)68(22)(65)(68)—(320)
Impacts of Tax Receivable Agreement——————(86)(86)
Non-cash compensation expenses——————1414
Transition and merger expenses(2)——————(2)
Winter Storm Uri impacts (c)(32)1—————(31)
Other, net1632110(9)(15)8
Adjusted EBITDA$(2)$873$138$45$(6)$(59)$(8)$981

(a)Includes $90 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $23 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.

Nine Months Ended September 30, 2023
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$462$396$1,049$481$442$23$(1,177)$1,676
Income tax expense——1———469470
Interest expense and related charges (a)19(15)—(8)24448450
Depreciation and amortization (b)784584885645—521,177
EBITDA before Adjustments5598391,53852948927(208)3,773
Unrealized net (gain) loss resulting from hedging transactions114703(1,024)(338)(278)(32)—(855)
Impacts of Tax Receivable Agreement——————128128
Non-cash compensation expenses——————6363
Transition and merger expenses(2)1——1—3939
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, net17(5)9538(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 the 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)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 $6 million), 2024 (approximately $11 million) and 2025 (approximately $25 million).

Nine Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$2,099$(1,455)$(910)$36$(525)$(154)$(53)$(962)
Income tax benefit——————(262)(262)
Interest expense and related charges (a)8(20)3(3)22194186
Depreciation and amortization (b)109467545264929521,277
EBITDA before Adjustments2,216(1,008)(362)59(474)(123)(69)239
Unrealized net (gain) loss resulting from hedging transactions(1,602)2,2608054947342—2,027
Impacts of Tax Receivable Agreement——————2929
Non-cash compensation expenses——————4848
Transition and merger expenses7—1———1018
Winter Storm Uri impacts (c)(95)(52)—————(147)
Other, net382162174(44)44
Adjusted EBITDA$564$1,221$450$110$16$(77)$(26)$2,258

(a)Includes $261 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $63 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 and Nine Months Ended September 30, 2023 Compared to Three and Nine Months Ended September 30, 2022

Three Months Ended September 30,Favorable (Unfavorable) ChangeNine Months Ended September 30,Favorable (Unfavorable) Change
2023202220232022
Operating revenues:
Revenues in ERCOT$2,878$2,422$456$6,570$5,887$683
Revenues in Northeast/Midwest574609(35)1,4961,800(304)
Amortization expense12(1)—1(1)
Unrealized net gains (losses) on hedging activities(70)225(295)95(812)907
Total operating revenues3,3833,2581258,1616,8761,285
Fuel, purchased power costs and delivery fees:
Purchases from affiliates(2,201)(2,020)(181)(4,799)(4,473)(326)
Unrealized net gains (losses) on hedging activities with affiliates (a)167(1,428)1,595(193)2,409(2,602)
Unrealized net gains (losses) on hedging activities———(16)5(21)
Delivery fees(779)(684)(95)(1,789)(1,758)(31)
Other costs(24)(29)5(82)(96)14
Total fuel, purchased power costs and delivery fees(2,837)(4,161)1,324(6,879)(3,913)(2,966)
Net income (loss)$245$(1,227)$1,472$462$2,099$(1,637)
Adjusted EBITDA$173$(2)$175$642$564$78
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT22,64319,7202,92354,71150,7563,955
Sales volumes in Northeast/Midwest7,9358,729(794)19,96526,161(6,196)
Total retail electricity sales volumes30,57828,4492,12974,67676,917(2,241)
Weather (North Texas average) - percent of normal (b):
Cooling degree days121.7%108.1%115.2%112.1%
Heating degree days—%—%81.7%111.8%

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

(b)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 and nine months ended September 30, 2023 compared to the three and nine months ended September 30, 2022.

Three Months Ended September 30, 2023 Compared to 2022Nine Months Ended September 30, 2023 Compared to 2022
Higher margins driven by seasonality of power costs$148$154
Winter Storm Uri impact, including bill credits2452
Lower margins due to mild weather in 2023—(107)
Lower bad debt expense115
Other driven by higher selling costs and revenue-based taxes due to higher revenues in ERCOT(8)(26)
Change in Adjusted EBITDA$175$78
Change in unrealized net gains/(losses) on hedging activities1,300(1,716)
Bill credits and other costs related to Winter Storm Uri(24)(49)
Decrease in depreciation and amortization expenses1031
Change in other expenses1119
Change in Net income (loss)$1,472$(1,637)

Generation — Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022

Three Months Ended September 30,
TexasEastWestSunset
20232022202320222023202220232022
Operating revenues:
Electricity sales$214$700$341$757$167$178$241$91
Capacity revenue from ISO/RTO——1214——8—
Sales to affiliates1,6801,442426458—295120
Rolloff of unrealized net gains (losses) representing positions settled in the current period5862535957—54(67)154
Unrealized net gains (losses) on hedging activities(888)19(106)(240)1761(43)(230)
Unrealized net gains (losses) on hedging activities with affiliates(78)1,213(81)80—1(8)119
Other revenues3———1—(2)(1)
Operating revenues1,5173,6276511,126344236224253
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs(505)(975)(369)(1,006)(72)(120)(183)(153)
Fuel for generation facilities and purchased power costs from affiliates2(3)(2)1———1
Unrealized gains (losses) from hedging activities24(52)33627(34)824
Unrealized gains (losses) on hedging activities with affiliates—3—(1)———(2)
Ancillary and other costs(228)(92)(8)(13)(1)(1)(1)(2)
Fuel, purchased power costs and delivery fees(707)(1,119)(376)(983)(46)(155)(176)(132)
Net income (loss)$438$2,156$29$(119)$264$72$(44)$31
Adjusted EBITDA$950$873$315$138$87$45$102$(6)
Production volumes (GWh):
Natural gas facilities15,63512,65416,97615,1181,4651,460
Lignite and coal facilities6,7436,6435,0385,713
Nuclear facilities5,2105,009
Solar facilities247250
Capacity factors:
CCGT facilities77.2%69.6%69.2%62.6%65.0%65.0%
Lignite and coal facilities79.3%78.1%49.8%56.5%
Nuclear facilities98.3%94.5%
Weather - percent of normal (a):
Cooling degree days120.5%105.2%96.7%111.2%93.2%112.9%111.5%107.7%
Heating degree days—%—%101.8%119.6%—%—%—%111.3%

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

Three Months Ended September 30,Three Months Ended September 30,
2023202220232022
Market pricingAverage Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)$109.32$100.54PJM West Hub$42.93$111.21
AEP Dayton Hub$40.00$106.07
Average NYMEX Henry Hub natural gas price ($/MMBtu)$2.58$7.96NYISO Zone C$35.46$87.63
Massachusetts Hub$39.88$99.52
Average natural gas price (a):Indiana Hub$42.99$109.24
TetcoM3 ($/MMBtu)$1.39$7.10Northern Illinois Hub$39.36$100.59
Algonquin Citygates ($/MMBtu)$1.93$7.57CAISO NP15$59.65$105.25

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

(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 September 30, 2023 compared to the three months ended September 30, 2022.

Three Months Ended September 30, 2023 Compared to 2022
TexasEastWestSunset
Favorable change in revenue net of fuel$100$185$37$111
Unfavorable change in other operating costs(24)(6)(5)—
Favorable/(unfavorable) change in selling, general and administrative expenses1(2)2(3)
Other——8—
Change in Adjusted EBITDA$77$177$42$108
Favorable/(unfavorable) change in depreciation and amortization—26(26)1
Change in unrealized net gains/(losses) on hedging activities(1,792)(57)181(175)
PJM capacity performance default impacts—3—(4)
Other (including interest expenses)(3)(1)(5)(5)
Change in Net income (loss)$(1,718)$148$192$(75)

The unfavorable change in Texas segment results was driven by unrealized hedging losses due to increases in forward power prices in the three months ended September 30, 2023 compared to unrealized hedging gains due to decreases in forward power prices in the three months ended September 30, 2022. The unfavorable change in unrealized hedging impacts was partially offset by higher revenue net of fuel in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due to high asset availability despite the fact that our power plants ran longer and more frequently than in 2022.

The favorable change in East segment results was driven by higher revenue net of fuel in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due primarily to strong plant operating performance and higher energy margins reflecting the effectiveness of our comprehensive hedging strategy driving higher realized energy margins.

The favorable change in West segment results was driven by higher revenue net of fuel in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due primarily to increased output from battery ESS assets which came online in 2023 (see Note 3). The change in West segment results was also driven by higher unrealized hedging gains due to more significant decreases in forward power prices in the three months ended September 30, 2023 compared to the three months ended September 30, 2022.

The unfavorable change in Sunset segment results was primarily driven by unrealized hedging losses due to decreases in forward coal prices in the three months ended September 30, 2023 compared to unrealized hedging gains due to increases in forward coal prices in the three months ended September 30, 2022. The unfavorable change in the Sunset segment results due to unrealized hedging losses was partially offset by higher revenue net of fuel in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due primarily to the effectiveness of our comprehensive hedging strategy.

Generation — Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

Nine Months Ended September 30,
TexasEastWestSunset
20232022202320222023202220232022
Operating revenues:
Electricity sales$405$1,302$1,051$1,975$497$405$612$253
Capacity revenue from ISO/RTO——424——3556
Sales to affiliates3,3342,7461,1971,37195259353
Rolloff of unrealized net gains (losses) representing positions settled in the current period865441482(12)2952(130)230
Unrealized net gains (losses) on hedging activities(1,163)(865)95(359)267(79)448(726)
Unrealized net gains (losses) on hedging activities with affiliates(388)(1,715)440(580)(3)4144(105)
Other revenues8—(2)1——(2)(6)
Operating revenues3,0611,9093,3052,4007993871,36655
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs(1,170)(1,967)(1,458)(2,644)(269)(249)(412)(436)
Fuel for generation facilities and purchased power costs from affiliates10(6)(10)2———2
Unrealized gains (losses) from hedging activities(17)(119)714645(26)(184)126
Unrealized gains (losses) from hedging activities with affiliates—(2)—————2
Ancillary and other costs(369)(248)(33)(28)(2)(4)(3)(7)
Fuel, purchased power costs and delivery fees(1,546)(2,342)(1,494)(2,524)(226)(279)(599)(313)
Net income (loss)$396$(1,455)$1,049$(910)$481$36$442$(525)
Adjusted EBITDA$1,540$1,221$526$450$196$110$305$16
Production volumes (GWh):
Natural gas facilities32,80926,30445,47040,8723,7413,525
Lignite and coal facilities17,90318,37611,35516,236
Nuclear facilities14,47114,369
Solar facilities638679
Capacity factors:
CCGT facilities57.1%49.3%62.8%57.4%55.9%52.3%
Lignite and coal facilities71.0%72.9%37.9%54.1%
Nuclear facilities92.0%91.4%
Weather - percent of normal (a):
Cooling degree days113.5%110.4%89.3%108.2%78.4%111.4%110.4%113.9%
Nine Months Ended September 30,
TexasEastWestSunset
20232022202320222023202220232022
Heating degree days81.5%129.4%85.3%98.9%154.3%95.4%85.5%101.6%

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

Nine Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Market pricingAverage Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)$56.26$67.08PJM West Hub$38.20$87.53
AEP Dayton Hub$36.16$83.66
Average NYMEX Henry Hub natural gas price ($/MMBtu)$2.46$6.66NYISO Zone C$30.12$70.09
Massachusetts Hub$41.49$95.91
Average natural gas price (a):Indiana Hub$39.49$86.77
TetcoM3 ($/MMBtu)$1.94$6.87Northern Illinois Hub$32.96$76.68
Algonquin Citygates ($/MMBtu)$3.02$9.46CAISO NP15$64.35$75.19

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

(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 nine months ended September 30, 2023 compared to the nine months ended September 30, 2022.

Nine Months Ended September 30, 2023 Compared to 2022
TexasEastWestSunset
Favorable change in revenue net of fuel$447$111$78$303
Unfavorable change in other operating costs(79)(28)(11)(4)
Favorable/(unfavorable) change in selling, general and administrative expenses5(7)2(7)
Other(54)—17(3)
Change in Adjusted EBITDA$319$76$86$289
Favorable/(unfavorable) change in depreciation and amortization957(30)4
Change in unrealized net gains on hedging activities1,5571,829387751
Impairment of long-lived assets———(49)
PJM capacity performance default impacts—(3)—(6)
Winter Storm Uri impact (ERCOT default uplift)(54)———
Other (including interest expenses)20—2(22)
Change in Net income$1,851$1,959$445$967

The favorable change in Texas segment results was primarily driven by lower unrealized hedging losses due to less material increases in forward power prices in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022. The change in Texas segment results was also driven by higher revenue net of fuel in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 due to strong generation performance and the effectiveness of our comprehensive hedging strategy.

The favorable changes in East, West and Sunset segment results were primarily driven by unrealized hedging gains due to decreases in forward power prices in the nine months ended September 30, 2023 compared to unrealized hedging losses due to material increases in power prices in the nine months ended September 30, 2022.

The change in East segment results was also driven by higher revenue net of fuel in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 due primarily to strong plant operating performance and higher energy margins reflecting the effectiveness of our comprehensive hedging strategy driving higher realized energy margins, partially offset by higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices in the first quarter of 2023.

The change in West segment results was also driven by higher revenue net of fuel in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 due to increased output from battery ESS assets which is due to bringing new assets online in 2023 and assets being partially offline in 2022 (see Note 3).

The change in Sunset segment results was also driven by higher revenue net of fuel in the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 due primarily to the effectiveness of our comprehensive hedging strategy. A $49 million impairment of assets related to our Kincaid generation facility was recognized in the first quarter of 2023. See Note 19 to the Financial Statements for more information concerning the impairment.

Asset Closure Segment — Three and Nine Months Ended September 30, 2023 Compared to Three and Nine Months Ended September 30, 2022

Three Months Ended September 30,Favorable (Unfavorable) ChangeNine Months Ended September 30,Favorable (Unfavorable) Change
2023202220232022
Operating revenues$—$95$(95)$—$297$(297)
Fuel, purchased power costs and delivery fees(1)(39)38(2)(275)273
Operating costs$(15)$(32)$17$(52)$(125)$73
Depreciation and amortization—(1)1—(29)29
Selling, general and administrative expenses(7)(12)5(24)(33)9
Operating loss(23)11(34)(78)(165)87
Other income7611051491
Other deductions————(1)1
Interest expense and related charges(1)(1)—(4)(2)(2)
Income (loss) before income taxes(17)16(33)23(154)177
Net income (loss)$(17)$16$(33)$23$(154)$177
Adjusted EBITDA$(24)$(59)$35$(6)$(77)$71
Production volumes (GWh)—1,449(1,449)—8,653(8,653)

For the three and nine months ended September 30, 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 gains related to coal and power derivatives of $59 million and $17 million in the three and nine months ended September 30, 2022, respectively. Operating costs for the three and nine months ended September 30, 2023 and 2022 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. Other income for the nine months ended September 30, 2023, includes a gain of $89 million from the sale of property in Freestone County, Texas. Results were also impacted in the three and nine months ended September 30, 2023 compared to the three and nine months ended September 30, 2022 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 nine months ended September 30, 2023 and 2022. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $855 million in unrealized net gains and $2.027 billion in unrealized net losses for the nine months ended September 30, 2023 and 2022, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

Nine Months Ended September 30,
20232022
Commodity contract net liability at beginning of period$(3,148)$(866)
Settlements/termination of positions (a)1,5851,166
Changes in fair value of positions in the portfolio (b)(730)(3,193)
Other activity (c)(108)79
Commodity contract net liability at end of period$(2,401)$(2,814)

(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 as of September 30, 2023, 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, 2023
Source of fair valueLess than 1 year1-3 years4-5 yearsExcess of 5 yearsTotal
Prices actively quoted$(414)$(222)$2$—$(634)
Prices provided by other external sources(435)(48)——(483)
Prices based on models(435)(611)(115)(123)(1,284)
Total$(1,284)$(881)$(113)$(123)$(2,401)

FINANCIAL CONDITION

Cash Flows

Operating Cash Flows — Cash provided by operating activities totaled $4.572 billion and $92 million for the nine months ended September 30, 2023 and 2022, respectively. The favorable change of $4.480 billion was primarily driven by (a) a decrease in net margin deposits of $2.271 billion in the nine months ended September 30, 2023 as compared to an increase in net margin deposits of $1.805 billion in the nine months ended September 30, 2022 related to commodity contracts which support our comprehensive hedging strategy, including the impacts of cash margin deposits returned and replaced with amounts posted under an affiliate financing agreement (see Note 11 to the Financial Statements) and (b) cash from operations exclusive of net margin deposits, partially offset by $544 million of securitization proceeds from ERCOT in 2022 (see Note 1 to the Financial Statements).

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 $333 million and $361 million for the nine months ended September 30, 2023 and 2022, respectively. The difference represents 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 $1.382 billion and $886 million for the nine months ended September 30, 2023 and 2022, respectively. The increase of $496 million was driven by (a) a $353 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) and (b) $218 million in net purchases of environmental allowances in the nine months ended September 30, 2023 compared to $15 million in net sales in the nine months ended September 30, 2022, partially offset by $90 million in higher proceeds from the sale of assets driven by our sale of property in Freestone County, Texas in 2023.

Nine Months Ended September 30,Increase (Decrease)
20232022
Capital expenditures, including LTSA prepayments$(575)$(471)$(104)
Nuclear fuel purchases(174)(173)(1)
Growth and development expenditures(513)(265)(248)
Total capital expenditures(1,262)(909)(353)
Net sales (purchases) of environmental allowances(218)15(233)
Net investments in nuclear decommissioning trust fund securities(17)(18)1
Proceeds from sales of assets1112190
Other investing activity45(1)
Cash used in investing activities$(1,382)$(886)$(496)

Financing Cash Flows — Cash used in financing activities totaled $490 million in the nine months ended September 30, 2023 and cash provided by financing activities totaled $3 million for the nine months ended September 30, 2022. The $493 million increase in cash used was primarily driven by (a) $1.075 billion of net repayments of short-term debt and accounts receivable financing in the nine months ended September 30, 2023 compared to $625 million of net borrowings of accounts receivable financing in the nine months ended September 30, 2022 driven by changes in collateral posting requirements and (b) $1.5 billion principal amount of senior secured notes issued in May 2022, partially offset by (1) $1.75 billion principal amount of senior secured and senior unsecured notes issued in September 2023 and (2) lower share repurchases in 2023.

Nine Months Ended September 30,Increase (Decrease)
20232022
Share repurchases$(866)$(1,590)$724
Issuances of senior notes (see Note 12)1,7501,498252
Net long-term borrowings (repayments), including the forward capacity agreements(21)(232)211
Net short-term borrowings (repayments)(650)—(650)
Net borrowings (repayments) under the accounts receivable financing facilities(425)625(1,050)
Dividends paid to common stockholders(228)(227)(1)
Dividends paid to preferred stockholders(75)(76)1
Other financing activity25520
Cash provided by (used in) financing activities$(490)$3$(493)

Debt Activity

In May 2024 and July 2024, $400 million of 4.875% Senior Secured Notes and $1.5 billion of 3.550% Senior Secured Notes, respectively, will reach maturity. We plan to fund these upcoming principal payments using a combination of cash on hand and new debt issuances. Increases in interest rates will likely result in increased borrowing costs. See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 12 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 nine months ended September 30, 2023:

September 30, 2023December 31, 2022Change
Cash and cash equivalents (a)$3,170$455$2,715
Vistra Operations Credit Facilities — Revolving Credit Facility (b)8491,236(387)
Vistra Operations — Commodity-Linked Facility (c)401808(407)
Total available liquidity (d)(e)$4,420$2,499$1,921

____________

(a)See the Condensed Consolidated Statements of Cash Flows in the Financial Statements and Cash Flows above for details of the increase in cash and cash equivalents for the nine months ended September 30, 2023. The increase includes proceeds from the issuance of $1.75 billion principal amount of Vistra Operations senior secured and senior unsecured notes in September 2023 that are expected to be used, together with cash on hand, to fund the Transactions.

(b)The decrease in availability for the nine months ended September 30, 2023 was driven by a $437 million increase in letters of credit outstanding under the facility and the maturity of $200 million of commitments under the Non-Extended Revolving Credit Facility, partially offset by $250 million in net repayments of borrowings under the facility.

(c)As of both September 30, 2023 and December 31, 2022, the borrowing bases are less than the facility limit of $1.35 billion. As of September 30, 2023, available capacity reflects the borrowing base of $401 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, in part, to the expiration of certain deemed 2023 hedges and would increase in size in a rising commodity price environment in accordance with the terms of the Commodity-Linked Facility. The Commodity-Linked Facility was amended in October 2023, increasing the aggregate commitments to $1.575 billion and extending the term to October 2024. The deemed hedge portfolio was also updated to reflect current hedge positions, including the addition of the 2025 deemed hedges, resulting in an increase of the borrowing base to $1.233 billion as of October 3, 2023.

(d)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.

(e)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities. See Note 12 to the Financial Statements for detail on our Secured LOC Facilities.

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, Eligible Assets (see Note 11 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 12 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.

As of September 30, 2023, we received or posted cash and letters of credit for commodity hedging activities as follows:

  • $1.312 billion in cash or Eligible Assets have been posted with counterparties as compared to $3.137 billion posted as of December 31, 2022;

  • $50 million in cash has been received from counterparties as compared to $39 million received as of December 31, 2022;

  • $2.778 billion in letters of credit have been posted with counterparties as compared to $2.314 billion posted as of December 31, 2022; and

  • $45 million in letters of credit have been received from counterparties as compared to $74 million received as of 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 $34 million in state income tax payments, offset by $12 million in state tax refunds, and $10 million in TRA payments in the next 12 months.

For the nine months ended September 30, 2023, there were no federal income tax payments, $31 million in state income tax payments, $12 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, 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, 2023, we were in compliance with the Vistra Operations Credit Agreement and Secured LOC Facilities financial covenants. Although the period ended September 30, 2023 was not a compliance period for the Vistra Operations Commodity-Linked Credit Agreement, we would have been in compliance with this financial covenant if it was required to be tested at such time.

See Note 12 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, 2023, Vistra has posted letters of credit in the amount of $91 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 $900 million in the form of letters of credit, $30 million in the form of a surety bond and $2 million of cash as of September 30, 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 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 $2.493 billion and zero, respectively, as of September 30, 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, 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 and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), 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, 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 Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes and 6.950% Senior Secured Notes, respectively, 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.

Guarantees

See Note 13 to the Financial Statements for discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 13 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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