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 2021 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, 2022. 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, 2022 and 2021 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 2021 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 16 to the Financial Statements for further information concerning our reportable business segments.

CEO Transition

In March 2022, Vistra announced that the Board had named Jim Burke as its next Chief Executive Officer (CEO), effective August 1, 2022. Mr. Burke, who previously served as President and Chief Financial Officer, also joined the Company's Board upon assuming his new role. Vistra's previous CEO and director, Curt Morgan, will serve as a special advisor to Mr. Burke and the Board until April 30, 2023. The transition from Mr. Morgan to Mr. Burke was a product of the Company's formal succession planning process. In July 2022, the Company announced the appointment of Kris Moldovan as the Company's Executive Vice President and Chief Financial Officer, effective August 1, 2022.

Significant Activities and Events and Items Influencing Future Performance

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 11 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.

Solar Generation and Energy Storage Projects — 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 contract in April 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 September 2020, we announced the planned development, at a cost of approximately $850 million, of up to 768 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 the first nine months of 2022. We will only invest in these growth projects if we are confident in the expected returns. See Note 2 to the Financial Statements for a summary of our solar and battery energy storage projects.

CO**2 Reductions — In June 2022 and September 2022, we retired the Zimmer coal generation facility and the Joppa generation facilities, respectively. See Note 3 to the Financial Statements for a summary of our planned generation retirements.

Inflation Reduction Act of 2022

In August 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA), which, among other things, implements substantial new and modified energy tax credits, including a nuclear production tax credit (PTC), a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% alternative minimum tax 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 corporate alternative minimum tax is not applicable in our next fiscal year since it is based on a three-year average annual adjusted financial statement income in excess of $1 billion. The excise tax is not expected to have a material impact on our financial statements. We have taken the corporate alternative minimum tax 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.

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.

Moss Landing Outages

In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. A review found the root cause originated in systems separate from the battery system. The facility was offline as we performed the work necessary to return the facility to service. Restoration work on the facility was completed in June 2022. Moss Landing Phases II and III were not affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery ESS. A review found the root cause originated in systems separate from the battery system. The facility was offline as we performed the work necessary to return the facility to service. Restoration work on the facility was completed in September 2022. Moss Landing Phases I and III were not affected by this incident.

These incidents did not have a material impact on our results of operations.

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.

The weather event resulted in a $2.9 billion negative impact on the Company's pre-tax earnings in the nine months ended September 30, 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 below. 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.

As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were charged and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri. In October 2021, the PUCT issued a debt obligation order approving ERCOT's $2.1 billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we received $544 million in proceeds from ERCOT in the second quarter of 2022. We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the debt obligation order. Accordingly, we recognized the $544 million in expected proceeds as an expense reduction in the fourth quarter of 2021 within fuel, purchased power costs and delivery fees in our consolidated statements of operation. The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event.

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 12 to the Financial Statements for more information about our dividend program.

Preferred Stock Offerings

In October 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering). The net proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed below).

In December 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Framework. The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We have used and will continue to use an amount equal to the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments in accordance with the Green Finance Framework.

See Note 12 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock.

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. The Share Repurchase Program superseded the $1.5 billion share repurchase program previously announced in September 2020 (2020 Share Repurchase Program). On August 4, 2022, the Board authorized an incremental $1.25 billion for repurchases under the Share Repurchase Program. We expect to complete repurchases under the current $3.25 billion Share Repurchase Program by the end of 2023.

In the nine months ended September 30, 2022, 63,459,123 shares of our common stock were repurchased under the Share Repurchase Program for approximately $1.493 billion at an average price of $23.52 per share of common stock (shares repurchased include 850,349 of unsettled shares repurchased for $18 million as of September 30, 2022). As of September 30, 2022, approximately $1.348 billion of the total authorized of $3.25 billion was available for additional repurchases under the Share Repurchase Program.

From October 1, 2022 through November 1, 2022, 7,076,619 of our common stock had been repurchased under the Share Repurchase Program for $156 million at an average price per share of common stock of $22.04, and at November 1, 2022, $1.192 billion of the total authorized of $3.25 billion was available for repurchase under the Share Repurchase Program.

Since the Share Repurchase Program became effective in October 2021, 89,866,107 shares of our common stock were repurchased for approximately $2.058 billion at an average price of $22.90 per share of common stock.

See Note 12 to the Financial Statements for more information concerning the Share Repurchase Program.

Macroeconomic Conditions

Global market demand, geopolitical events and high natural gas price volatility have resulted in increased market prices for energy, and we expect these conditions to persist, in particular in the near term. Due in large part to the Russia and Ukraine conflict as well as other factors, we have experienced substantial shifts in commodity prices, which in turn have (i) facilitated our comprehensive hedging strategy which we believe has positioned us to lock in significant revenues and Adjusted EBITDA opportunities in 2023 and beyond, (ii) led to significant mark-to-market impacts on forward commodity derivative instruments, and (iii) combined with our comprehensive hedging strategy, resulted in significant increases in our collateral posting obligations and required liquidity to support these net liabilities. Additionally, we continue to monitor domestic drivers of gas prices, including the pace of investment and buildout of liquefied natural gas (LNG) export capabilities, which have the potential to more closely align U.S. natural gas pricing with the further elevated international gas markets over the next couple of years. See also Financial Condition for further discussion of our collateral posting obligations and liquidity management activities.

We continue to monitor the impacts of energy volatility on the retail and associated default service markets as well. As electricity pricing has trended higher, we have observed increased customer migration to the default service provider in territories outside of Texas, where default service rates do not yet fully reflect the higher commodity pricing environment. Generators (including Vistra) with contracts to serve a percentage of the resultingly higher than planned default service load (previously awarded through the default service auction process) are likely to incur losses on these particular default service contracts, as the underlying cost to provide the incremental power may have subsequently risen above the contracted revenue rate. We anticipate these losses could have a negative impact on our East segment through the end of these default service contracts in mid-2023.

Accordingly, with forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods. As of September 30, 2022, we have hedged approximately 70% of our expected generation volumes on average for the three-year period 2023 to 2025 (with approximately 90% hedged for 2023).

Changes to the geopolitical situation and the inflationary environment, among other factors, have also created supply chain constraints that have reduced the availability and increased the costs of certain fuels, such as coal, as well as reduced the availability of certain equipment and supply relevant to construction of renewables projects. For example, we are closely monitoring the status of the tentative agreement between labor unions and railroad companies, which remains subject to ratification by the labor unions. While any failure to ratify such agreement would not present immediate risk of service disruption, any future rail strike could require us to hold additional coal inventory, which could have significant financial costs and limit our ability to operate our coal-fueled power plants at expected levels. Further, we are proactively managing through 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 from 2022 to 2023 and beyond. In addition, our Vistra Zero operational and development projects are anticipated to benefit from the impact of the recently passed IRA. The inflationary environment has also led to and is expected to cause further increases in interest rates, resulting in increased refinancing or borrowing costs, including project financing for our development projects.

Additionally, we are closely monitoring developments of the Russia and Ukraine conflict including sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, as well as actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. Our 2022 refueling has not been affected by the Russia and Ukraine conflict. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel, and therefore, we expect to have enough nuclear fuel to support all our refueling needs for the next few years. We are taking affirmative action by including mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility. If imports from Russia were restricted, U.S. merchant nuclear power generators could be challenged in their refueling operations in future years.

Debt Activity

We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities and/or reduce ongoing interest expense. While the financial impacts resulting from Winter Storm Uri and higher margining requirements as a result of increasing power prices have caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet. See Note 10 to the Financial Statements for details of our debt activity and Note 9 to the Financial Statements for details of our accounts receivable financing.

Vistra Operations Credit Agreement Amendments — In April 2022 and July 2022, the Vistra Operations Credit Agreement was amended to, among other things, (i) establish new classes of extended revolving credit commitments maturing in April 2027 in aggregate amounts of $2.8 billion and $725 million as of April 2022 and July 2022, respectively, (ii) require Vistra Operations to terminate at least $350 million in revolving commitments maturing April 29, 2027 by December 30, 2022 or earlier if Vistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity of Vistra Operations and its guarantors, and (iii) appoint certain additional revolving letter of credit issuers. See Note 10 to the Financial Statements for details of the Vistra Operations Credit Agreement amendments.

Commodity-Linked Revolving Credit Facility — In February 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides for a senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes.

In order to support our comprehensive hedging strategy, in May 2022, we entered into an amendment to our Commodity-Linked Facility to increase the aggregate available commitments from $1.0 billion to $2.0 billion and to provide the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility by an additional $1.0 billion to a facility size of $3.0 billion. Subsequent amendments in May 2022 and June 2022 increased the aggregate available commitments under the Commodity-Linked Facility from $2.0 billion to $2.25 billion.

On October 5, 2022, Vistra initiated an amendment to the Commodity-Linked Facility to, among other things, (i) extend the maturity date to October 2023 and (ii) reduce the aggregate available commitments to $1.25 billion. On October 21, 2022, the Commodity-Linked Facility was further amended to increase the aggregate available commitments to $1.35 billion.

See Note 10 to the Financial Statements for more information concerning the Commodity-Linked Facility.

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 September 30, 2022 were as follows:

20222023
Nuclear/Renewable/Coal Generation:
Texas95%92%
Sunset93%77%
Gas Generation:
Texas90%75%
East99%88%
West90%96%

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, 2022.

Balance 20222023
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price$2$10
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price$(2)$(9)
Gas Generation: $1.00/MWh increase in spark spread$1$12
Gas Generation: $1.00/MWh decrease in spark spread$(1)$(11)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$1$(20)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$(1)$14
East:
Gas Generation: $1.00/MWh increase in spark spread$—$7
Gas Generation: $1.00/MWh decrease in spark spread$—$(6)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$1$(6)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$(1)$6
West:
Gas Generation: $1.00/MWh increase in spark spread$—$—
Gas Generation: $1.00/MWh decrease in spark spread$—$—
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$—$1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$—$(1)
Sunset:
Coal Generation: $2.50/MWh increase in power price$1$15
Coal Generation: $2.50/MWh decrease in power price$(1)$(14)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$—$(8)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$—$8

PJM Auction Results

In June 2022, Vistra reported its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2023-2024, and the table below lists clearing price per MW-day and our cleared capacity volumes by zone:

Clearing Price per MW-dayEast Segment MW ClearedSunset Segment MW ClearedTotal MW Cleared
RTO zone$34.132,890—2,890
ComEd zone$34.131,1514081,559
DEOK zone$34.1311924935
EMAAC zone$49.49828—828
MAAC zone$49.49545—545
ATSI zone$34.13112—112
Total$37.205,5371,3326,869

RESULTS OF OPERATIONS

In the three and nine months ended September 30, 2022, 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 the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business. Notably, 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 executed on our share repurchase strategy.

Consolidated Financial Results — Three and Nine Months Ended September 30, 2022 Compared to Three and Nine Months Ended September 30, 2021

Three Months Ended September 30,Favorable (Unfavorable) $ ChangeNine Months Ended September 30,Favorable (Unfavorable) $ Change
2022202120222021
Operating revenues$5,146$2,991$2,155$9,859$8,763$1,096
Fuel, purchased power costs and delivery fees(3,139)(1,763)(1,376)(7,580)(7,827)247
Operating costs(400)(372)(28)(1,250)(1,173)(77)
Depreciation and amortization(390)(468)78(1,214)(1,355)141
Selling, general and administrative expenses(323)(269)(54)(894)(771)(123)
Impairment of long-lived assets————(38)38
Operating income (loss)894119775(1,079)(2,401)1,322
Other income1016(6)88108(20)
Other deductions(5)(5)—(18)(13)(5)
Interest expense and related charges(71)(124)53(186)(288)102
Impacts of Tax Receivable Agreement863551(29)31(60)
Income (loss) before income taxes91441873(1,224)(2,563)1,339
Income tax (expense) benefit(236)(31)(205)262569(307)
Net income (loss)$678$10$668$(962)$(1,994)$1,032
Three Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Operating revenues$3,258$3,627$1,126$236$280$68$(3,449)$5,146
Fuel, purchased power costs and delivery fees(4,161)(1,119)(983)(155)(144)(27)3,450(3,139)
Operating costs(43)(193)(58)(10)(71)(25)—(400)
Depreciation and amortization(36)(135)(187)4(19)1(18)(390)
Selling, general and administrative expenses(238)(33)(18)(5)(10)(11)(8)(323)
Operating income (loss)(1,220)2,147(120)70366(25)894
Other income211——6—10
Other deductions(5)(1)——1——(5)
Interest expense and related charges(4)9—2(1)(1)(76)(71)
Impacts of Tax Receivable Agreement——————8686
Income (loss) before income taxes(1,227)2,156(119)723611(15)914
Income tax expense——————(236)(236)
Net income (loss)$(1,227)$2,156$(119)$72$36$11$(251)$678
Three Months Ended September 30, 2021
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Operating revenues$2,160$843$508$90$(62)$(60)$(488)$2,991
Fuel, purchased power costs and delivery fees(1,095)(482)(496)(78)(86)(14)488(1,763)
Operating costs(38)(163)(57)(9)(65)(40)—(372)
Depreciation and amortization(53)(179)(164)(15)(27)(13)(17)(468)
Selling, general and administrative expenses(192)(23)(19)(7)(8)(11)(9)(269)
Operating income (loss)782(4)(228)(19)(248)(138)(26)119
Other income17——26—16
Other deductions—(2)——(1)—(2)(5)
Interest expense and related charges(2)3(5)1(1)(1)(119)(124)
Impacts of Tax Receivable Agreement——————3535
Income (loss) before income taxes7814(233)(18)(248)(133)(112)41
Income tax expense(2)—————(29)(31)
Net income (loss)$779$4$(233)$(18)$(248)$(133)$(141)$10

Consolidated operating income increased $775 million to $894 million in the three months ended September 30, 2022 compared to the three months ended September 30, 2021. The change in results was primarily driven by $320 million in pre-tax unrealized mark-to-market gains on commodity hedging transactions in 2022 compared to $589 million in pre-tax unrealized mark-to-market losses on commodity hedging transactions in 2021, which was driven by a decrease in forward power and natural gas price curves during the three months ended September 30, 2022 compared to an increase in forward power and natural gas price curves during the three months ended September 30, 2021. Included within these unrealized mark-to-market changes are pre-tax net unrealized gains of $217 million and pre-tax net unrealized losses of $357 million in the three months ended September 30, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term.

Depreciation expense for the three months ended September 30, 2021 includes an immaterial out-of-period adjustment to correct for the net understatement of depreciation expense related to prior periods. See Note 1 to the Financial Statements.

Interest expense and related charges decreased $53 million to $71 million in the three months ended September 30, 2022 compared to the three months ended September 30, 2021 driven by unrealized mark-to-market gains on interest rate swaps of $90 million in 2022 compared to $13 million in 2021. The change in unrealized results is driven by an increase in interest rates during the three months ended September 30, 2022. This favorable variance is partially offset by an increase in interest paid/accrued of $32 million driven by higher average borrowings during the three months ended September 30, 2022. See Note 17 to the Financial Statements.

For the three months ended September 30, 2022 and 2021, the Impacts of the Tax Receivable Agreement totaled income of $86 million and $35 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.

For the three months ended September 30, 2022, income tax expense totaled $236 million and the effective tax rate was 25.8%. For the three months ended September 30, 2021, income tax expense totaled $31 million and the effective tax rate was 75.6%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Nine Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Operating revenues$6,876$1,909$2,400$387$56$296$(2,065)$9,859
Fuel, purchased power costs and delivery fees(3,913)(2,342)(2,524)(279)(340)(248)2,066(7,580)
Operating costs(111)(602)(189)(32)(213)(103)—(1,250)
Depreciation and amortization(109)(404)(545)(26)(56)(22)(52)(1,214)
Selling, general and administrative expenses(622)(99)(50)(17)(29)(30)(47)(894)
Operating income (loss)2,121(1,538)(908)33(582)(107)(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(583)(96)(315)(1,224)
Income tax benefit——————262262
Net income (loss)$2,099$(1,455)$(910)$36$(583)$(96)$(53)$(962)
Nine Months Ended September 30, 2021
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Operating revenues$5,829$1,458$1,738$171$188$(79)$(542)$8,763
Fuel, purchased power costs and delivery fees(2,345)(4,133)(1,269)(164)(384)(74)542(7,827)
Operating costs(96)(527)(181)(26)(194)(148)(1)(1,173)
Depreciation and amortization(160)(462)(553)(30)(78)(21)(51)(1,355)
Selling, general and administrative expenses(539)(62)(56)(22)(24)(38)(30)(771)
Impairment of long-lived assets—————(38)—(38)
Operating income (loss)2,689(3,726)(321)(71)(492)(398)(82)(2,401)
Other income172——5264108
Other deductions(4)(7)————(2)(13)
Interest expense and related charges(7)10(11)9(1)(1)(287)(288)
Impacts of Tax Receivable Agreement——————3131
Income (loss) before income taxes2,679(3,651)(332)(62)(488)(373)(336)(2,563)
Income tax (expense) benefit(2)—————571569
Net income (loss)$2,677$(3,651)$(332)$(62)$(488)$(373)$235$(1,994)

Operating loss decreased $1.322 billion to $1.079 billion in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. The change in results is driven by the $2.9 billion realized loss associated with Winter Storm Uri in the first quarter of 2021. Partially offsetting the 2021 Winter Storm Uri impact, results for the nine months ended September 30, 2022 were unfavorably impacted by a $1.256 billion increase in pre-tax unrealized mark-to-market losses on derivative positions. Power and natural gas forward market curves moved up during the nine months ended September 30, 2022 driving the pre-tax unrealized mark-to-market losses on commodity hedging transactions. Included within these unrealized mark-to-market changes are pre-tax net unrealized losses of $780 million and $357 million recorded in the nine months ended September 30, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term. We believe the overall increase in forward power and natural gas prices during 2022 has positioned us to significantly benefit operating results in 2023 and beyond.

Depreciation expense for the nine months ended September 30, 2021 includes an immaterial out-of-period adjustment to correct for the net understatement of depreciation expense related to prior periods. See Note 1 to the Financial Statements.

Interest expense and related charges decreased $102 million to $186 million in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 driven by unrealized mark-to-market gains on interest rate swaps of $261 million in 2022 compared to $92 million in 2021 which is due to a more significant rise in interest rates in the nine months ended September 30, 2022, partially offset by an increase in interest paid/accrued of $75 million driven by higher average borrowings in 2022. See Note 17 to the Financial Statements.

For the nine months ended September 30, 2022 and 2021, the Impacts of the Tax Receivable Agreement totaled expense of $29 million and income of $31 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.

For the nine months ended September 30, 2022, income tax benefit totaled $262 million and the effective tax rate was 21.4%. For the nine months ended September 30, 2021, income tax benefit totaled $569 million, and the effective tax rate was 22.2%. See Note 6 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 material 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, 2022 Compared to Three and Nine Months Ended September 30, 2021

Three Months Ended September 30,Favorable (Unfavorable) $ ChangeNine Months Ended September 30,Favorable (Unfavorable) $ Change
2022202120222021
Net income (loss)$678$10$668$(962)$(1,994)$1,032
Income tax expense (benefit)23631205(262)(569)307
Interest expense and related charges (a)71124(53)186288(102)
Depreciation and amortization (b)413489(76)1,2771,416(139)
EBITDA before Adjustments1,398654744239(859)1,098
Unrealized net (gain) loss resulting from commodity hedging transactions (c)(320)589(909)2,0277711,256
Generation plant retirement expenses—5(5)419(15)
Fresh start/purchase accounting impacts—(17)17—(96)96
Impacts of Tax Receivable Agreement(86)(35)(51)29(31)60
Non-cash compensation expenses1411348408
Transition and merger expenses(2)(2)—18(17)35
Impairment of long-lived assets—2(2)—40(40)
Winter Storm Uri impact (d)(31)(33)2(147)866(1,013)
Other, net8(1)9401129
Adjusted EBITDA$981$1,173$(192)$2,258$744$1,514

(a)Includes unrealized mark-to-market net gains on interest rate swaps of $90 million and $13 million for the three months ended September 30, 2022 and 2021, respectively, and unrealized mark-to-market net gains on interest rate swaps of $261 million and $92 million for the nine months ended September 30, 2022 and 2021, respectively.

(b)Includes nuclear fuel amortization in the Texas segment of $23 million and $21 million for the three months ended September 30, 2022 and 2021, respectively, and $63 million and $61 million for the nine months ended September 30, 2022 and 2021, respectively.

(c)Net pre-tax unrealized mark-to-market gains on commodity and hedging transactions were driven by a decrease in power and natural gas price curves during the three months ended September 30, 2022. Net pre-tax unrealized mark-to-market losses on commodity and hedging transactions were driven by the increase in power and natural gas forward market curves during the nine months ended September 30, 2022. Additionally, we recorded pre-tax net unrealized gains of $217 million and pre-tax net unrealized losses of $357 million in the three months ended September 30, 2022 and 2021, respectively, and net unrealized losses of $780 million and $357 million in the nine months ended September 30, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term.

(d)For the nine months ended September 30, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: the allocation of ERCOT default uplift charges which are expected to be paid over several decades under current protocols, accrual of Koch earn-out amounts that we paid in the second quarter of 2022, future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will 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. Accordingly, for the three and nine months ended September 30, 2022 and the three months ended September 30, 2021, includes reductions to Adjusted EBITDA attributable to bill credit applications of $32 million, $98 million and $33 million, respectively. Also includes a reduction to Adjusted EBITDA related to a reduction in the allocation of ERCOT default uplift charges of zero and $56 million for the three and nine months ended September 30, 2022, respectively, attributable to ERCOT receiving payments that reduced the market wide default balance.

Three Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$(1,227)$2,156$(119)$72$36$11$(251)$678
Income tax expense——————236236
Interest expense and related charges (a)4(9)—(2)117671
Depreciation and amortization (b)36158187(4)19(1)18413
EBITDA before Adjustments(1,187)2,30568665611791,398
Unrealized net (gain) loss resulting from hedging transactions1,203(1,436)68(22)(74)(59)—(320)
Generation plant retirement expenses————1(1)——
Impacts of Tax Receivable Agreement——————(86)(86)
Non-cash compensation expenses——————1414
Transition and merger expenses(2)——————(2)
Winter Storm Uri impacts (c)(32)1—————(31)
Other, net163219(8)(15)8
Adjusted EBITDA$(2)$873$138$45$(8)$(57)$(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)Includes the application of future bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri.

Three Months Ended September 30, 2021
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$779$4$(233)$(18)$(248)$(133)$(141)$10
Income tax expense2——2931
Interest expense and related charges (a)2(3)5(1)11119124
Depreciation and amortization (b)5320016415271317489
EBITDA before Adjustments836201(64)(4)(220)(119)24654
Unrealized net (gain) loss resulting from hedging transactions(739)65425439279102—589
Generation plant retirement expenses—————415
Fresh start/purchase accounting impacts(2)(2)——(5)(8)—(17)
Impacts of Tax Receivable Agreement——————(35)(35)
Non-cash compensation expenses——————1111
Transition and merger expenses(4)—————2(2)
Impairment of long-lived assets—2—————2
Winter Storm Uri impacts (c)(31)(2)—————(33)
Other, net5531(2)1(14)(1)
Adjusted EBITDA$65$858$193$36$52$(20)$(11)$1,173

(a)Includes $13 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $21 million in Texas segment.

(c)Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: future bill credits related to Winter Storm Uri, partially offset by the allocation of additional ERCOT default uplift charges, which are expected to be paid over several decades under current protocols, and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will 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.

Nine Months Ended September 30, 2022
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$2,099$(1,455)$(910)$36$(583)$(96)$(53)$(962)
Income tax benefit——————(262)(262)
Interest expense and related charges (a)8(20)3(3)22194186
Depreciation and amortization (b)109467545265622521,277
EBITDA before Adjustments2,216(1,008)(362)59(525)(72)(69)239
Unrealized net (gain) loss resulting from hedging transactions(1,602)2,26080549532(17)—2,027
Generation plant retirement expenses————6(2)—4
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, net382162125(44)40
Adjusted EBITDA$564$1,221$450$110$25$(86)$(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)Includes 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 are expected to be paid over several decades under current protocols. We estimate bill credit amounts to be applied in future periods are for the remainder of 2022 (approximately $35 million), 2023 (approximately $52 million), 2024 (approximately $41 million) and 2025 (approximately $1 million).

Nine Months Ended September 30, 2021
RetailTexasEastWestSunsetAsset ClosureEliminations / Corporate and OtherVistra Consolidated
Net income (loss)$2,677$(3,651)$(332)$(62)$(488)$(373)$235$(1,994)
Income tax expense (benefit)2—————(571)(569)
Interest expense and related charges (a)7(10)11(9)11287288
Depreciation and amortization (b)160523553307821511,416
EBITDA before Adjustments2,846(3,138)232(41)(409)(351)2(859)
Unrealized net (gain) loss resulting from hedging transactions(2,840)2,269407120593222—771
Generation plant retirement expenses—————19—19
Fresh start/purchase accounting impacts1(3)(74)—(7)(13)—(96)
Impacts of Tax Receivable Agreement——————(31)(31)
Non-cash compensation expenses——————4040
Transition and merger expenses(2)————(15)—(17)
Impairment of long-lived assets—2———38—40
Winter Storm Uri impacts (c)354511——1——866
Other, net1798214(30)11
Adjusted EBITDA$376$(350)$573$81$179$(96)$(19)$744

(a)Includes $92 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $61 million in Texas segment.

(c)Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: the allocation of ERCOT default uplift charges which are expected to be paid over several decades under current protocols, accrual of Koch earn-out amounts that we paid in the second quarter of 2022, future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will 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.

Retail Segment — Three and Nine Months Ended September 30, 2022 Compared to Three and Nine Months Ended September 30, 2021

Three Months Ended September 30,Favorable (Unfavorable) ChangeNine Months Ended September 30,Favorable (Unfavorable) Change
2022202120222021
Operating revenues:
Revenues in ERCOT$2,422$1,917$505$5,887$4,521$1,366
Revenues in Northeast/Midwest609624(15)1,8001,71585
Amortization expense22—1(1)2
Unrealized net gains (losses) on hedging activities (a)225(383)608(812)(406)(406)
Total operating revenues3,2582,1601,0986,8765,8291,047
Fuel, purchased power costs and delivery fees:
Purchases from affiliates(2,020)(1,607)(413)(4,473)(3,784)(689)
Unrealized net gains (losses) on hedging activities with affiliates (b)(1,428)1,117(2,545)2,4093,244(835)
Unrealized net gains on hedging activities—5(5)523
Delivery fees(684)(595)(89)(1,758)(1,472)(286)
Other costs (c)(29)(15)(14)(96)(335)239
Total fuel, purchased power costs and delivery fees(4,161)(1,095)(3,066)(3,913)(2,345)(1,568)
Net income (loss)$(1,227)$779$(2,006)$2,099$2,677$(578)
Adjusted EBITDA$(2)$65$(67)$564$376$188
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT19,72017,7321,98850,75644,2156,541
Sales volumes in Northeast/Midwest8,72910,034(1,305)26,16127,558(1,397)
Total retail electricity sales volumes28,44927,76668376,91771,7735,144
Weather (North Texas average) - percent of normal (d):
Cooling degree days108.1%93.2%112.1%89.6%
Heating degree days—%—%111.8%118.1%

(a)Includes pre-tax unrealized net gains of $217 million and net unrealized losses of $357 million for the three months ended September 30, 2022 and 2021, respectively, and pre-tax net unrealized losses of $780 million and $357 million for the nine months ended September 30, 2022 and 2021, respectively, recognized due to the discontinuance of NPNS accounting on retail electric contract portfolios 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)For the nine months ended September 30, 2021, includes $162 million of future bill credits to large commercial and industrial customers.

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

The following table presents changes in net income and Adjusted EBITDA for the three and nine months ended September 30, 2022 compared to the three and nine months ended September 30, 2021.

Three Months Ended September 30, 2022 Compared to 2021Nine Months Ended September 30, 2022 Compared to 2021
Winter Storm Uri, including bill credits$(45)$453
Timing of commodity costs, including self-help gains in 2021, intra-year seasonality and backwardation on multi-year customer contracts(9)(232)
Higher margins reflecting ERCOT performance and favorable weather in 20223746
Other primarily driven by higher bad debt expense due to higher revenues in 2022(50)(79)
Change in Adjusted EBITDA$(67)$188
Unfavorable impact of unrealized net gains on hedging activities(1,942)(1,238)
Future bill credits and other costs related to Winter Storm Uri1449
Decrease in depreciation and amortization expenses1751
Change in transition and merger and other expenses(15)(28)
Change in net income$(2,006)$(578)

Generation — Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

Three Months Ended September 30,
TexasEastWestSunset
20222021202220212022202120222021
Operating revenues:
Electricity sales$700$462$757$411$178$134$112$183
Capacity revenue from ISO/RTO——14(13)—1—39
Sales to affiliates1,4421,07845841321120113
Rolloff of unrealized net gains (losses) representing positions settled in the current period253(17)57(56)545517445
Unrealized net gains (losses) on hedging activities19(153)(240)2251(101)(259)(322)
Unrealized net gains (losses) on hedging activities with affiliates1,213(527)80(472)1—134(118)
Other revenues——————(1)(2)
Operating revenues3,6278431,12650823690280(62)
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs(975)(458)(1,006)(536)(120)(84)(168)(199)
Fuel for generation facilities and purchased power costs from affiliates(3)111——1(1)
Unrealized gains (losses) from hedging activities(52)433649(34)727116
Unrealized gains (losses) on hedging activities with affiliates3—(1)———(2)—
Ancillary and other costs(92)(68)(13)(10)(1)(1)(2)(2)
Fuel, purchased power costs and delivery fees(1,119)(482)(983)(496)(155)(78)(144)(86)
Net income (loss)$2,156$4$(119)$(233)$72$(18)$36$(248)
Adjusted EBITDA$873$858$138$193$45$36$(8)$52
Production volumes (GWh):
Natural gas facilities12,6549,59715,11814,7601,4601,635
Lignite and coal facilities6,6437,9696,3518,153
Nuclear facilities5,0095,254
Solar facilities250135
Capacity factors:
CCGT facilities69.6%52.7%62.6%60.7%65.0%72.6%
Lignite and coal facilities78.1%93.7%55.7%71.5%
Nuclear facilities98.6%103.5%
Weather - percent of normal (a):
Cooling degree days105.2%92.4%111.2%101.3%112.9%94.5%107.7%109.6%
Heating degree days—%—%119.6%37.2%—%—%111.3%47.7%

(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,
2022202120222021
Market pricingAverage Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)$100.54$38.64PJM West Hub$111.21$51.37
AEP Dayton Hub$106.07$50.29
Average NYMEX Henry Hub natural gas price ($/MMBtu)$7.96$4.27NYISO Zone C$87.63$43.95
Massachusetts Hub$99.52$52.69
Average natural gas price (a):Indiana Hub$109.24$51.59
TetcoM3 ($/MMBtu)$7.10$3.75Northern Illinois Hub$100.59$48.19
Algonquin Citygates ($/MMBtu)$7.57$3.86CAISO NP15$109.24$71.25

(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 September 30, 2022 compared to the three months ended September 30, 2021.

Three Months Ended September 30, 2022 Compared to 2021
TexasEastWestSunset
Favorable/(unfavorable) change in revenue net of fuel$61$(56)$8$(48)
Winter Storm Uri impact3—(1)—
Favorable/(unfavorable) change in other operating costs(32)(1)2(8)
Favorable/(unfavorable) change in selling, general and administrative expenses(18)2—(5)
Other1——1
Change in Adjusted EBITDA$15$(55)$9$(60)
Favorable/(unfavorable) change in depreciation and amortization42(23)198
Change in unrealized net gains/(losses) on hedging activities2,09018661353
Impairment of long-lived assets2———
Generation plant retirement, transition and merger expenses———(1)
Fresh start/purchase accounting impacts(2)——(5)
Winter Storm Uri impact (ERCOT default uplift and Koch earn-out)(3)———
Other (including interest and COVID-19 related expenses)861(11)
Change in Net income (loss)$2,152$114$90$284

The change in Texas segment results was primarily driven by unrealized hedging gains in the three months ended September 30, 2022 compared to unrealized hedging losses in the three months ended September 30, 2021 due to decreases in forward power prices in the three months ended September 30, 2022 compared to increases in forward power prices in the three months ended September 30, 2021. Additionally, revenue net of fuel is higher in the three months ended September 30, 2022 compared to the three months ended September 30, 2021 due primarily to strong generation fleet performance during periods of higher pricing.

The change in East segment results was primarily driven by lower unrealized hedging losses in the three months ended September 30, 2022 compared to the three months ended September 30, 2021 due to decreases in forward power prices in the three months ended September 30, 2022 compared to increases in forward power prices in the three months ended September 30, 2021. Additionally, revenue net of fuel is lower in the three months ended September 30, 2022 compared to the three months ended September 30, 2021 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices and lower capacity revenue.

The change in West segment results was primarily driven by unrealized hedging gains in the three months ended September 30, 2022 compared to unrealized hedging losses in the three months ended September 30, 2021 due to decreases in forward power prices in the three months ended September 30, 2022 compared to increases in forward power prices in the three months ended September 30, 2021.

The change in Sunset segment results was driven by an unfavorable change in revenue net of fuel due primarily to lower generation volumes from coal plants due to industry-wide fuel delivery challenges in the three months ended September 30, 2022.

Generation — Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Nine Months Ended September 30,
TexasEastWestSunset
20222021202220212022202120222021
Operating revenues:
Electricity sales$1,302$1,502$1,975$986$405$302$323$530
Capacity revenue from ISO/RTO——4(14)—16399
Sales to affiliates2,7462,3101,3711,17853353293
Rolloff of unrealized net gains (losses) representing positions settled in the current period441(170)(12)(24)524426020
Unrealized net gains (losses) on hedging activities(865)(31)(359)357(79)(179)(819)(472)
Unrealized net gains (losses) on hedging activities with affiliates(1,715)(2,153)(580)(819)4—(118)(272)
Other revenues——174——(6)(10)
Operating revenues1,9091,4582,4001,73838717156188
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs(1,967)(2,439)(2,644)(1,321)(249)(176)(480)(508)
Fuel for generation facilities and purchased power costs from affiliates(6)(1)2———2(1)
Unrealized (gains) losses from hedging activities(119)8514679(26)15143131
Unrealized (gains) losses from hedging activities with affiliates(2)—————2—
Ancillary and other costs(248)(1,778)(28)(27)(4)(3)(7)(6)
Fuel, purchased power costs and delivery fees(2,342)(4,133)(2,524)(1,269)(279)(164)(340)(384)
Net income (loss)$(1,455)$(3,651)$(910)$(332)$36$(62)$(583)$(488)
Adjusted EBITDA$1,221$(350)$450$573$110$81$25$179
Production volumes (GWh):
Natural gas facilities26,30423,14240,87240,7813,5253,998
Lignite and coal facilities18,37619,44118,21921,730
Nuclear facilities14,36915,343
Solar facilities679357
Capacity factors:
CCGT facilities49.3%43.1%57.4%56.7%52.3%59.8%
Lignite and coal facilities72.9%77.1%53.9%64.2%
Nuclear facilities95.4%101.8%
Weather - percent of normal (a):
Cooling degree days110.4%89.8%108.2%107.2%111.4%95.5%113.9%112.1%
Heating degree days129.4%122.9%98.9%95.3%95.4%108.2%101.6%94.4%

(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,
2022202120222021
Market pricingAverage Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)$67.08$186.71PJM West Hub$87.53$39.95
AEP Dayton Hub$83.66$40.15
Average NYMEX Henry Hub natural gas price ($/MMBtu)$6.66$3.52NYISO Zone C$70.09$31.94
Massachusetts Hub$95.91$46.96
Average natural gas price (a):Indiana Hub$86.77$43.99
TetcoM3 ($/MMBtu)$6.87$3.11Northern Illinois Hub$76.68$37.77
Algonquin Citygates ($/MMBtu)$9.46$3.93CAISO NP15$75.19$52.96

(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 nine months ended September 30, 2022 compared to the nine months ended September 30, 2021.

Nine Months Ended September 30, 2022 Compared to 2021
TexasEastWestSunset
Favorable/(unfavorable) change in revenue net of fuel$141$(72)$31$(106)
Winter Storm Uri impact1,551(50)—(17)
Unfavorable change in other operating costs(85)(8)(7)(34)
Favorable/(unfavorable) change in selling, general and administrative expenses(34)75(11)
Other(2)——14
Change in Adjusted EBITDA$1,571$(123)$29$(154)
Favorable change in depreciation and amortization568422
Change in unrealized net gains/(losses) on hedging activities9(398)7161
Impairment of long-lived assets2———
Generation plant retirement expenses———(6)
Fresh start/purchase accounting impacts(3)(74)—(7)
Winter Storm Uri impact (ERCOT default uplift and Koch earn-out)563——1
Other (including interest and COVID-19 related expenses)(2)9(6)(12)
Change in Net income (loss)$2,196$(578)$98$(95)

The change in Texas segment results was primarily driven by the Winter Storm Uri impacts in 2021. The increases in revenue net of fuel and operating costs are due to strong generation fleet performance during periods of higher pricing and inflationary pressures, respectively, in the nine months ended September 30, 2022.

The change in East segment results was primarily driven by higher unrealized hedging losses in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 due to increases in forward power prices and favorable Winter Storm Uri impacts recognized in the nine months ended September 30, 2021. Additionally, revenue net of fuel is lower in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices and lower capacity revenue.

The change in West segment results was driven by lower unrealized losses in the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021 as forward power prices increased more in the nine months ended September 30, 2021. Additionally, revenues net of fuel are higher in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 reflecting higher realized margins from our battery ESS projects (see Note 2 to the Financial Statements).

The change in Sunset segment results was driven by an unfavorable change in revenue net of fuel due primarily to lower generation volumes from coal plants due to industry-wide fuel delivery challenges in the nine months ended September 30, 2022.

Asset Closure Segment — Three and Nine Months Ended September 30, 2022 Compared to Three and Nine Months Ended September 30, 2021

Three Months Ended September 30,Favorable (Unfavorable) ChangeNine Months Ended September 30,Favorable (Unfavorable) Change
2022202120222021
Operating revenues$68$(60)$128$296$(79)$375
Fuel, purchased power costs and delivery fees(27)(14)(13)(248)(74)(174)
Operating costs$(25)$(40)$15$(103)$(148)$45
Depreciation and amortization1(13)14(22)(21)(1)
Selling, general and administrative expenses(11)(11)—(30)(38)8
Impairment of long-lived assets————(38)38
Operating income (loss)6(138)144(107)(398)291
Other income66—1426(12)
Other deductions———(1)—(1)
Interest expense and related charges(1)(1)—(2)(1)(1)
Income (loss) before income taxes11(133)144(96)(373)277
Net income (loss)$11$(133)$144$(96)$(373)$277
Adjusted EBITDA$(57)$(20)$(37)$(86)$(96)$10
Production volumes (GWh)8113,301(2,490)6,6706,852(182)

Results and volumes for the Asset Closure segment include those from the Zimmer and Joppa generation plants that we retired in May 2022 and September 2022, respectively. Operating costs for the three and nine months ended September 30, 2022 and 2021 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The change in Asset Closure segment results for both the three and nine months ended September 30, 2022 is primarily due to severance and impairment expense recorded in the three months ended September 30, 2021, in connection with plant closure announcements (see Note 3 to the Financial Statements).

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, 2022 and 2021. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $2.027 billion and $771 million in unrealized net losses, respectively, for the nine months ended September 30, 2022 and 2021, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

Nine Months Ended September 30,
20222021
Commodity contract net liability at beginning of period$(866)$(75)
Settlements/termination of positions (a)1,166(202)
Changes in fair value of positions in the portfolio (b)(3,193)(569)
Other activity (c)79(116)
Commodity contract net liability at end of period$(2,814)$(962)

(a)Represents reversals of previously recognized unrealized gains and 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 September 30, 2022, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Maturity dates of unrealized commodity contract net liability at September 30, 2022
Source of fair valueLess than 1 year1-3 years4-5 yearsExcess of 5 yearsTotal
Prices actively quoted$(882)$(643)$(1)$—$(1,526)
Prices provided by other external sources(147)(114)4—(257)
Prices based on models(377)(509)(104)(41)(1,031)
Total$(1,406)$(1,266)$(101)$(41)$(2,814)

FINANCIAL CONDITION

Operating Cash Flows

Cash provided by operating activities totaled $92 million for the nine months ended September 30, 2022 compared to cash used in operating activities of $493 million for the nine months ended September 30, 2021. The favorable change of $585 million was primarily driven by lower cash from operations in 2021 due to Winter Storm Uri impacts and $544 million of securitization proceeds from ERCOT in 2022 (see Note 1 to the Financial Statements), partially offset by margin deposits of $1.805 billion in 2022 as compared to $767 million in 2021 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 $361 million and $196 million for the nine months ended September 30, 2022 and 2021, 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 $886 million and $843 million for the nine months ended September 30, 2022 and 2021, respectively. Capital expenditures totaled $909 million and $790 million for the nine months ended September 30, 2022 and 2021, respectively, and consisted of the following:

Nine Months Ended September 30,
20222021
Capital expenditures, including LTSA prepayments$471$437
Nuclear fuel purchases$173$30
Growth and development expenditures$265$323
Capital expenditures$909$790

Cash used in investing activities for the nine months ended September 30, 2022 and 2021 also reflected net sales of environmental allowances of $15 million and net purchases of environmental allowances of $145 million, respectively. In the nine months ended September 30, 2022 and 2021, we received insurance proceeds for reimbursement of capital expenditures of $15 million and $74 million, respectively.

Financing Cash Flows

Cash provided by financing activities totaled $3 million and $1.279 billion for the nine months ended September 30, 2022 and 2021, respectively. The change was primarily driven by:

  • the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021;

  • $1.590 billion in cash paid for share repurchases in 2022, including $114 million of unsettled share repurchases accrued as of December 31, 2021 and excluding $18 million of unsettled share repurchases accrued as of September 30, 2022, compared to $175 million in cash paid in 2021;

  • $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 in 2021; and

  • dividends of $76 million paid to preferred stockholders in 2022.

These decreases in cash provided by financing activities are partially offset by:

  • the issuance of $1.5 billion principal amount of Vistra Operations senior secured notes in May 2022; and

  • net borrowings of $625 million under the accounts receivable financing facilities in 2022 compared to net borrowings of $175 million in 2021.

Debt Activity

The maturities of our long-term debt are relatively modest until 2024. See Note 9 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 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, 2022:

September 30, 2022December 31, 2021Change
Cash and cash equivalents$535$1,325$(790)
Vistra Operations Credit Facilities — Revolving Credit Facility1,2021,254(52)
Vistra Operations — Commodity-Linked Facility (a)1,701—1,701
Total available liquidity (b)$3,438$2,579$859

____________

(a)As of September 30, 2022, available capacity reflects the borrowing base which is lower than the aggregate commitments of $2.25 billion. The Commodity-Linked Facility was amended in October 2022, decreasing the aggregate commitments to $1.35 billion and extending the term to October 2023.

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

The $859 million increase in available liquidity for the nine months ended September 30, 2022 was primarily driven by $1.5 billion principal amount of Vistra Operations senior secured notes issued, $1.701 billion in available capacity under the Commodity-Linked Facility under the aggregate commitments in effect as of September 30, 2022, $1.0 billion in additional aggregate commitments under the Revolving Credit Facility resulting from the Credit Agreement Amendments and $625 million in net cash borrowings under the accounts receivable financing facilities, partially offset by $1.590 billion in cash paid for share repurchases, $909 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), a $1.052 billion increase in letters of credit outstanding under the Revolving Credit Facility, $227 million in dividends paid to common stockholders and $76 million in dividends paid to preferred stockholders.

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.

Higher commodity market prices combined with our comprehensive hedging strategy have resulted in significantly increased collateral posting obligations during the first nine months of 2022. The majority of this collateral relates to hedges in place through 2023 and is expected to be returned as we satisfy our obligations under those contracts. As of November 1, 2022, Vistra had approximately $4.08 billion of cash and availability under its credit facilities to meet its liquidity needs. The Company believes it has additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital, or reducing capital expenditures, planned voluntary debt repayments or operating costs.

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 10 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 September 30, 2022, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

  • $3.066 billion in cash has been posted with counterparties as compared to $1.263 billion posted at December 31, 2021;

  • $37 million in cash has been received from counterparties as compared to $39 million received at December 31, 2021;

  • $2.635 billion in letters of credit have been posted with counterparties as compared to $1.558 billion posted at December 31, 2021; and

  • $88 million in letters of credit have been received from counterparties as compared to $35 million received at December 31, 2021.

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 $45 million in state income tax payments, offset by $5 million in state tax refunds, and $1 million in TRA payments in the next 12 months.

For the nine months ended September 30, 2022, there were no federal income tax payments, $27 million in state income tax payments, $8 million in state income tax refunds and no TRA payments.

Financial Covenants

The Vistra Operations Credit Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00 (or, during a collateral suspension period, a total net leverage ratio not to exceed 5.50 million to 1.00). As of September 30, 2022, we were in compliance with this financial covenant.

See Note 10 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 September 30, 2022, Vistra has posted letters of credit in the amount of $74 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 $512 million in the form of letters of credit, $30 million in the form of a surety bond and $16 million of cash at September 30, 2022 (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 $2.522 billion at September 30, 2022.

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 11 to the Financial Statements for discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 11 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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