VISTRA CORP. 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 theSEC . 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. IfVistra 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 endedSeptember 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
All dollar amounts in the tables in the following discussion and analysis are
stated in millions of
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 theU.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. 52 -------------------------------------------------------------------------------- Table of Contents CEO Transition InMarch 2022 ,Vistra announced that the Board had namedJim Burke as its next Chief Executive Officer (CEO), effectiveAugust 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 toMr. Burke and the Board untilApril 30, 2023 . The transition fromMr. Morgan toMr. Burke was a product of the Company's formal succession planning process. InJuly 2022 , the Company announced the appointment ofKris Moldovan as the Company's Executive Vice President and Chief Financial Officer, effectiveAugust 1, 2022 .
Significant Activities and Events and Items Influencing Future Performance
Climate Change, Investments in Clean Energy and CO2 Reductions
Environmental Regulations - We are subject to extensive environmental regulation by governmental authorities, including theEPA 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 ofVistra'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 andEnergy Storage Projects - InJanuary 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 ourMoss Landing Power Plant site. The CPUC approved the resource adequacy contract inApril 2022 . InSeptember 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 inIllinois , based on the passage ofIllinois Senate Bill 2408, the Energy Transition Act. InSeptember 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 inTexas . Of this planned development inTexas , 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. CO2 Reductions - InJune 2022 andSeptember 2022 , we retired the Zimmer coal generation facility and theJoppa generation facilities, respectively. See Note 3 to the Financial Statements for a summary of our planned generation retirements.
Inflation Reduction Act of 2022
InAugust 2022 , theU.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
InOctober 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. 53 -------------------------------------------------------------------------------- Table of Contents Moss Landing Outages InSeptember 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 inJune 2022 . Moss Landing Phases II and III were not affected by this incident. InFebruary 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 inSeptember 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
The weather event resulted in a$2.9 billion negative impact on the Company's pre-tax earnings in the nine months endedSeptember 30, 2021 . The weather event resulted in a$2.2 billion negative impact on the Company's pre-tax earnings in the year endedDecember 31, 2021 , after taking into account approximately$544 million in securitization proceedsVistra received fromERCOT as further described below. The primary drivers of the loss were the need to procure power inERCOT 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 regularTexas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, theTexas legislature passed House Bill (HB) 4492 forERCOT to obtain financing to distribute to load-serving entities (LSEs) that were charged and paid toERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri. InOctober 2021 , the PUCT issued a debt obligation order approvingERCOT's $2.1 billion financing and the methodology for allocation of proceeds to the LSEs. InDecember 2021 ,ERCOT finalized the amount of allocations to the LSEs, and we received$544 million in proceeds fromERCOT in the second quarter of 2022. We concluded that the threshold for recognizing a receivable was met inDecember 2021 as the amounts to be received were determinable andERCOT 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 itsERCOT fleet for even colder temperatures and longer durations; carrying more backup generation into the peak seasons after accounting for weatherization investments andERCOT 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 andERCOT 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
InNovember 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. 54 -------------------------------------------------------------------------------- Table of Contents Preferred Stock Offerings InOctober 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). InDecember 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
InOctober 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 inOctober 2021 . The Share Repurchase Program superseded the$1.5 billion share repurchase program previously announced inSeptember 2020 (2020 Share Repurchase Program). OnAugust 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 endedSeptember 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 ofSeptember 30, 2022 ). As ofSeptember 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
Since the Share Repurchase Program became effective inOctober 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 theRussia andUkraine 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 alignU.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. 55 -------------------------------------------------------------------------------- Table of Contents 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 ofTexas , where default service rates do not yet fully reflect the higher commodity pricing environment. Generators (includingVistra ) 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 ofSeptember 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 theRussia andUkraine conflict including sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, as well as actions byRussia to limit energy deliveries, which may further impact commodity prices inEurope and globally. Our 2022 refueling has not been affected by theRussia andUkraine 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 fromRussia 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 - InApril 2022 andJuly 2022 , the Vistra Operations Credit Agreement was amended to, among other things, (i) establish new classes of extended revolving credit commitments maturing inApril 2027 in aggregate amounts of$2.8 billion and$725 million as ofApril 2022 andJuly 2022 , respectively, (ii) requireVistra Operations to terminate at least$350 million in revolving commitments maturingApril 29, 2027 byDecember 30, 2022 or earlier ifVistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity ofVistra 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. 56 -------------------------------------------------------------------------------- Table of Contents Commodity-Linked Revolving Credit Facility - InFebruary 2022 ,Vistra Operations entered into a credit agreement by and amongVistra Operations ,Vistra Intermediate , the lenders, joint lead arrangers and joint bookrunners party thereto, andCitibank, 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 whichVistra 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, inMay 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 inMay 2022 andJune 2022 increased the aggregate available commitments under the Commodity-Linked Facility from$2.0 billion to$2.25 billion . OnOctober 5, 2022 ,Vistra initiated an amendment to the Commodity-Linked Facility to, among other things, (i) extend the maturity date toOctober 2023 and (ii) reduce the aggregate available commitments to$1.25 billion . OnOctober 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
2022 2023
Nuclear/Renewable/Coal Generation:
Texas 95 % 92 %
Sunset 93 % 77 %
Gas Generation:
Texas 90 % 75 %
East 99 % 88 %
West 90 % 96 %
57-------------------------------------------------------------------------------- Table of Contents 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 ofSeptember 30, 2022 . Balance 2022 2023
Nuclear/Renewable/Coal Generation:
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 Sunset Segment MW Total
per MW-day East Segment MW Cleared Cleared MW Cleared
RTO zone $ 34.13 2,890 - 2,890
ComEd zone $ 34.13 1,151 408 1,559
DEOK zone $ 34.13 11 924 935
EMAAC zone $ 49.49 828 - 828
MAAC zone $ 49.49 545 - 545
ATSI zone $ 34.13 112 - 112
Total $ 37.20 5,537 1,332 6,869
58-------------------------------------------------------------------------------- Table of Contents RESULTS OF OPERATIONS In the three and nine months endedSeptember 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
Three Months Ended Favorable Nine Months Ended Favorable
September 30, (Unfavorable) September 30, (Unfavorable)
2022 2021 $ Change 2022 2021 $ Change
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) 894 119 775 (1,079) (2,401) 1,322
Other income 10 16 (6) 88 108 (20)
Other deductions (5) (5) - (18) (13) (5)
Interest expense and related
charges (71) (124) 53 (186) (288) 102
Impacts of Tax Receivable
Agreement 86 35 51 (29) 31 (60)
Income (loss) before income
taxes 914 41 873 (1,224) (2,563) 1,339
Income tax (expense) benefit (236) (31) (205) 262 569 (307)
Net income (loss) $ 678 $ 10 $ 668 $ (962) $ (1,994) $ 1,032
Three Months Ended September 30, 2022
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other 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) 70 36 6 (25) 894
Other income 2 1 1 - - 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 - - - - - - 86 86
Income (loss) before
income taxes (1,227) 2,156 (119) 72 36 11 (15) 914
Income tax expense - - - - - - (236) (236)
Net income (loss) $ (1,227) $ 2,156 $ (119) $ 72 $ 36 $ 11 $ (251) $ 678
59--------------------------------------------------------------------------------
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Three Months Ended
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other 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 income 1 7 - - 2 6 - 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 - - - - - - 35 35
Income (loss) before
income taxes 781 4 (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
For the three months endedSeptember 30, 2022 , income tax expense totaled$236 million and the effective tax rate was 25.8%. For the three months endedSeptember 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 theU.S. federal statutory rate. 60
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Nine Months Ended September 30, 2022
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other 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 income 2 65 1 - - 14 6 88 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 taxes 2,099 (1,455) (910) 36 (583) (96) (315) (1,224) Income tax benefit - - - - - - 262 262 Net income (loss)$ 2,099 $ (1,455) $ (910)
$ 36 $ (583) $ (96) $ (53)$ (962) Nine Months Ended September 30, 2021 Asset Eliminations / Vistra Retail Texas East West Sunset Closure Corporate and Other Consolidated
Operating revenues
$ 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 income 1 72 - - 5 26 4 108 Other deductions (4) (7) - - - - (2) (13) Interest expense and related charges (7) 10 (11) 9 (1) (1) (287) (288) Impacts of Tax Receivable Agreement - - - - - - 31 31 Income (loss) before income taxes 2,679 (3,651) (332) (62) (488) (373) (336) (2,563) Income tax (expense) benefit (2) - - - - - 571 569 Net income (loss)$ 2,677 $ (3,651) $ (332) $ (62) $ (488) $ (373) $ 235$ (1,994) 61
-------------------------------------------------------------------------------- Table of Contents Operating loss decreased$1.322 billion to$1.079 billion in the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 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 endedSeptember 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 endedSeptember 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 endedSeptember 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 endedSeptember 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 endedSeptember 30, 2022 compared to the nine months endedSeptember 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 endedSeptember 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 endedSeptember 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 endedSeptember 30, 2022 , income tax benefit totaled$262 million and the effective tax rate was 21.4%. For the nine months endedSeptember 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 theU.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 ofVistra 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).
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Adjusted EBITDA - Three and Nine Months Ended September 30, 2022 Compared to
Three and Nine Months Ended September 30, 2021
Three Months Ended Favorable Nine Months Ended Favorable
September 30, (Unfavorable) September 30, (Unfavorable)
2022 2021 $ Change 2022 2021 $ Change
Net income (loss) $ 678 $ 10 $
668
31 205 (262) (569) 307
Interest expense and related
charges (a) 71 124 (53) 186 288 (102)
Depreciation and amortization
(b) 413 489 (76) 1,277 1,416 (139)
EBITDA before Adjustments 1,398 654 744 239 (859) 1,098
Unrealized net (gain) loss
resulting from commodity
hedging transactions (c) (320) 589 (909) 2,027 771 1,256
Generation plant retirement
expenses - 5 (5) 4 19 (15)
Fresh start/purchase accounting
impacts - (17) 17 - (96) 96
Impacts of Tax Receivable
Agreement (86) (35) (51) 29 (31) 60
Non-cash compensation expenses 14 11 3 48 40 8
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, net 8 (1) 9 40 11 29
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 $56 million for the three
and nine months ended September 30, 2022 , respectively, attributable to ERCOT
receiving payments that reduced the market wide default balance.
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Three Months Ended September 30, 2022
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other ConsolidatedNet income (loss)$ (1,227) $ 2,156 $ (119) $ 72 $ 36 $ 11 $ (251) $ 678 Income tax expense - - - - - - 236 236 Interest expense and related charges (a) 4 (9) - (2) 1 1 76 71 Depreciation and amortization (b) 36 158 187 (4) 19 (1) 18 413 EBITDA before Adjustments (1,187) 2,305 68 66 56 11 79 1,398 Unrealized net (gain) loss resulting from hedging transactions 1,203 (1,436) 68 (22) (74) (59) - (320) Generation plant retirement expenses - - - - 1 (1) - - Impacts of Tax Receivable Agreement - - - - - - (86) (86) Non-cash compensation expenses - - - - - - 14 14 Transition and merger expenses (2) - - - - - - (2) Winter Storm Uri impacts (c) (32) 1 - - - - - (31) Other, net 16 3 2 1 9 (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
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other Consolidated
Net income (loss) $ 779 $ 4 $ (233) $ (18) $ (248) $ (133) $ (141) $ 10
Income tax expense 2 - - 29 31
Interest expense and related
charges (a) 2 (3) 5 (1) 1 1 119 124
Depreciation and amortization (b) 53 200 164 15 27 13 17 489
EBITDA before Adjustments 836 201 (64) (4) (220) (119) 24 654
Unrealized net (gain) loss
resulting from hedging
transactions (739) 654 254 39 279 102 - 589
Generation plant retirement
expenses - - - - - 4 1 5
Fresh start/purchase accounting
impacts (2) (2) - - (5) (8) - (17)
Impacts of Tax Receivable
Agreement - - - - - - (35) (35)
Non-cash compensation expenses - - - - - - 11 11
Transition and merger expenses (4) - - - - - 2 (2)
Impairment of long-lived assets - 2 - - - - - 2
Winter Storm Uri impacts (c) (31) (2) - - - - - (33)
Other, net 5 5 3 1 (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.
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(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
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other 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) 2 2 194 186
Depreciation and amortization
(b) 109 467 545 26 56 22 52 1,277
EBITDA before Adjustments 2,216 (1,008) (362) 59 (525) (72) (69) 239
Unrealized net (gain) loss
resulting from hedging
transactions (1,602) 2,260 805 49 532 (17) - 2,027
Generation plant retirement
expenses - - - - 6 (2) - 4
Impacts of Tax Receivable
Agreement - - - - - - 29 29
Non-cash compensation expenses - - - - - - 48 48
Transition and merger expenses 7 - 1 - - - 10 18
Winter Storm Uri impacts (c) (95) (52) - - - - - (147)
Other, net 38 21 6 2 12 5 (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 ).
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Nine Months Ended September 30, 2021
Asset Eliminations / Vistra
Retail Texas East West Sunset Closure Corporate and Other 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) 1 1 287 288
Depreciation and amortization
(b) 160 523 553 30 78 21 51 1,416
EBITDA before Adjustments 2,846 (3,138) 232 (41) (409) (351) 2 (859)
Unrealized net (gain) loss
resulting from hedging
transactions (2,840) 2,269 407 120 593 222 - 771
Generation plant retirement
expenses - - - - - 19 - 19
Fresh start/purchase accounting
impacts 1 (3) (74) - (7) (13) - (96)
Impacts of Tax Receivable
Agreement - - - - - - (31) (31)
Non-cash compensation expenses - - - - - - 40 40
Transition and merger expenses (2) - - - - (15) - (17)
Impairment of long-lived assets - 2 - - - 38 - 40
Winter Storm Uri impacts (c) 354 511 - - 1 - - 866
Other, net 17 9 8 2 1 4 (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.
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Retail Segment - Three and Nine Months Ended
Three Months Ended Favorable Nine Months Ended Favorable
September 30, (Unfavorable) September 30, (Unfavorable)
2022 2021 Change 2022 2021 Change
Operating revenues:
Revenues in ERCOT $ 2,422 $ 1,917 $ 505 $ 5,887 $ 4,521 $ 1,366
Revenues in Northeast/Midwest 609 624 (15) 1,800 1,715 85
Amortization expense 2 2 - 1 (1) 2
Unrealized net gains (losses) on
hedging activities (a) 225 (383) 608 (812) (406) (406)
Total operating revenues 3,258 2,160 1,098 6,876 5,829 1,047
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) 2,409 3,244
(835)
Unrealized net gains on hedging activities - 5 (5) 5 2 3 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 ERCOT 19,720 17,732 1,988 50,756 44,215 6,541 Sales volumes in Northeast/Midwest 8,729 10,034 (1,305) 26,161 27,558
(1,397)
Total retail electricity sales volumes 28,449 27,766 683 76,917 71,773 5,144 Weather (North Texas average) - percent of normal (d): Cooling degree days 108.1 % 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 endedSeptember 30, 2022 and 2021, respectively, and pre-tax net unrealized losses of$780 million and$357 million for the nine months endedSeptember 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 theTexas , East and Sunset segments. (c)For the nine months endedSeptember 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 onWeather Services International (WSI) data. 67 -------------------------------------------------------------------------------- Table of Contents The following table presents changes in net income and Adjusted EBITDA for the three and nine months endedSeptember 30, 2022 compared to the three and nine months endedSeptember 30, 2021 . Three Months Ended Nine Months Ended September 30, 2022 September 30, 2022 Compared to 2021 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
37 46
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 Uri
1 449
Decrease in depreciation and amortization expenses 17 51
Change in transition and merger and other expenses (15) (28)
Change in net income $ (2,006) $ (578)
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Generation - Three Months Ended
Three Months Ended
Texas East West Sunset
2022 2021 2022 2021 2022 2021 2022 2021
Operating revenues:
Electricity sales $ 700 $ 462 $ 757 $ 411 $ 178 $ 134 $ 112 $ 183
Capacity revenue from
ISO/RTO - - 14 (13) - 1 - 39
Sales to affiliates 1,442 1,078 458 413 2 1 120 113
Rolloff of unrealized net
gains (losses) representing
positions settled in the
current period 253 (17) 57 (56) 54 55 174 45
Unrealized net gains
(losses) on hedging
activities 19 (153) (240) 225 1 (101) (259) (322)
Unrealized net gains
(losses) on hedging
activities with affiliates 1,213 (527) 80 (472) 1 - 134 (118)
Other revenues - - - - - - (1) (2)
Operating revenues 3,627 843 1,126 508 236 90 280 (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) 1 1 1 - - 1 (1)
Unrealized gains (losses)
from hedging activities (52) 43 36 49 (34) 7 27 116
Unrealized gains (losses)
on hedging activities with
affiliates 3 - (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
9,597 15,118 14,760 1,460 1,635
Lignite and coal facilities 6,643 7,969 6,351 8,153
Nuclear facilities 5,009 5,254
Solar facilities 250 135
Capacity factors:
CCGT facilities 69.6 % 52.7 % 62.6 % 60.7 % 65.0 % 72.6 %
Lignite and coal facilities 78.1 % 93.7 % 55.7 % 71.5 %
Nuclear facilities 98.6 % 103.5 %
Weather - percent of normal
(a):
Cooling degree days 105.2 % 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
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Three Months Ended Three Months Ended
September 30, September 30,
2022 2021 2022 2021
Average Market On-Peak Power
Market pricing Prices ($MWh) (b):
Average ERCOT North power PJM West Hub $ 111.21 $ 51.37
price ($/MWh) $ 100.54 $ 38.64 AEP Dayton Hub $ 106.07 $ 50.29
Average NYMEX Henry Hub NYISO Zone C $ 87.63 $ 43.95
natural gas price ($/MMBtu)
$ 99.52 $ 52.69 Average natural gas price (a): Indiana Hub$ 109.24 $ 51.59 TetcoM3 ($/MMBtu)$ 7.10 $ 3.75 Northern Illinois Hub$ 100.59 $ 48.19
Algonquin Citygates ($/MMBtu)
$ 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 endedSeptember 30, 2022 compared to the three months endedSeptember 30, 2021 . Three Months
Ended
Texas East West Sunset
Favorable/(unfavorable) change in revenue net of fuel
3 - (1) -
Favorable/(unfavorable) change in other operating costs (32)
(1) 2 (8)
Favorable/(unfavorable) change in selling, general and
administrative expenses (18) 2 - (5)
Other 1 - - 1
Change in Adjusted EBITDA $ 15
42 (23) 19 8
Change in unrealized net gains/(losses) on hedging activities
2,090 186 61 353
Impairment of long-lived assets 2 - - -
Generation plant retirement, transition and merger expenses
- - - (1)
Fresh start/purchase accounting impacts (2) - - (5)
Winter Storm Uri impact (
(3) - - -
Other (including interest and COVID-19 related
expenses) 8 6 1 (11)
Change in Net income (loss) $ 2,152 The change inTexas segment results was primarily driven by unrealized hedging gains in the three months endedSeptember 30, 2022 compared to unrealized hedging losses in the three months endedSeptember 30, 2021 due to decreases in forward power prices in the three months endedSeptember 30, 2022 compared to increases in forward power prices in the three months endedSeptember 30, 2021 . Additionally, revenue net of fuel is higher in the three months endedSeptember 30, 2022 compared to the three months endedSeptember 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 endedSeptember 30, 2022 compared to the three months endedSeptember 30, 2021 due to decreases in forward power prices in the three months endedSeptember 30, 2022 compared to increases in forward power prices in the three months endedSeptember 30, 2021 . Additionally, revenue net of fuel is lower in the three months endedSeptember 30, 2022 compared to the three months endedSeptember 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. 70 -------------------------------------------------------------------------------- Table of Contents The change in West segment results was primarily driven by unrealized hedging gains in the three months endedSeptember 30, 2022 compared to unrealized hedging losses in the three months endedSeptember 30, 2021 due to decreases in forward power prices in the three months endedSeptember 30, 2022 compared to increases in forward power prices in the three months endedSeptember 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
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Generation - Nine Months Ended September 30, 2022 Compared to Nine Months Ended
September 30, 2021 Nine Months Ended
Texas East West Sunset
2022 2021 2022 2021 2022 2021 2022 2021
Operating revenues:
Electricity sales $ 1,302 $ 1,502 $ 1,975 $ 986 $ 405 $ 302 $ 323 $ 530
Capacity revenue from
ISO/RTO - - 4 (14) - 1 63 99
Sales to affiliates 2,746 2,310 1,371 1,178 5 3 353 293
Rolloff of unrealized net
gains (losses) representing
positions settled in the
current period 441 (170) (12) (24) 52 44 260 20
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 - - 1 74 - - (6) (10)
Operating revenues 1,909 1,458 2,400 1,738 387 171 56 188
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) 85 146 79 (26) 15 143
131
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 facilities 26,304 23,142 40,872 40,781 3,525 3,998 Lignite and coal facilities 18,376 19,441 18,219 21,730 Nuclear facilities 14,369 15,343 Solar facilities 679 357 Capacity factors: CCGT facilities 49.3 % 43.1 % 57.4 % 56.7 % 52.3 % 59.8 % Lignite and coal facilities 72.9 % 77.1 % 53.9 % 64.2 % Nuclear facilities 95.4 % 101.8 % Weather - percent of normal (a): Cooling degree days 110.4 % 89.8 % 108.2 % 107.2 % 111.4 % 95.5 % 113.9 % 112.1 % Heating degree days 129.4 % 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
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Nine Months Ended Nine Months Ended
September 30, September 30,
2022 2021 2022 2021
Average Market On-Peak Power
Market pricing Prices ($MWh) (b):
Average ERCOT North power PJM West Hub $ 87.53 $ 39.95
price
($/MWh) $ 67.08 $ 186.71 AEP Dayton Hub $ 83.66 $ 40.15
Average NYMEX Henry Hub NYISO Zone C $ 70.09 $ 31.94
natural gas price ($/MMBtu)
$ 95.91 $ 46.96 Average natural gas price (a): Indiana Hub$ 86.77 $ 43.99 TetcoM3 ($/MMBtu)$ 6.87 $ 3.11 Northern Illinois Hub$ 76.68 $ 37.77
Algonquin Citygates ($/MMBtu)
$ 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 endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 . Nine Months
Ended
Texas East West Sunset
Favorable/(unfavorable) change in revenue net of fuel
1,551 (50) - (17)
Unfavorable change in other operating costs (85) (8) (7) (34)
Favorable/(unfavorable) change in selling, general and
administrative expenses (34) 7 5 (11)
Other (2) - - 14
Change in Adjusted EBITDA $ 1,571 $ (123) $ 29 $ (154)
Favorable change in depreciation and amortization 56 8 4 22
Change in unrealized net gains/(losses) on hedging activities
9 (398) 71 61
Impairment of long-lived assets 2 - - -
Generation plant retirement expenses - - - (6)
Fresh start/purchase accounting impacts (3) (74) - (7)
Winter Storm Uri impact (
563 - - 1
Other (including interest and COVID-19 related expenses) (2)
9 (6) (12)
Change in Net income (loss) $ 2,196 The change inTexas 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 endedSeptember 30, 2022 . The change in East segment results was primarily driven by higher unrealized hedging losses in the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 due to increases in forward power prices and favorable Winter Storm Uri impacts recognized in the nine months endedSeptember 30, 2021 . Additionally, revenue net of fuel is lower in the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 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. 73 -------------------------------------------------------------------------------- Table of Contents The change in West segment results was driven by lower unrealized losses in the nine months endedSeptember 30, 2022 as compared to the nine months endedSeptember 30, 2021 as forward power prices increased more in the nine months endedSeptember 30, 2021 . Additionally, revenues net of fuel are higher in the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 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
Asset Closure Segment - Three and Nine Months Ended
Three Months Ended Favorable Nine Months Ended Favorable
September 30, (Unfavorable) September 30, (Unfavorable)
2022 2021 Change 2022 2021 Change
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 amortization 1 (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 income 6 6 - 14 26 (12)
Other deductions - - - (1) - (1)
Interest expense and related
charges (1) (1) - (2) (1) (1)
Income (loss) before income
taxes 11 (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) 811 3,301 (2,490) 6,670 6,852 (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).
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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
Nine Months Ended
2022 2021
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)
____________
(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
Maturity dates of unrealized
commodity contract net liability at
Less than Excess of
Source of fair value 1 year 1-3 years 4-5 years 5 years Total
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)
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Table of Contents FINANCIAL CONDITION Operating Cash Flows Cash provided by operating activities totaled$92 million for the nine months endedSeptember 30, 2022 compared to cash used in operating activities of$493 million for the nine months endedSeptember 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 fromERCOT 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 endedSeptember 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 endedSeptember 30, 2022 and 2021, respectively. Capital expenditures totaled$909 million and$790 million for the nine months endedSeptember 30, 2022 and 2021, respectively, and consisted of the following: Nine Months EndedSeptember 30, 2022
2021
Capital expenditures, including LTSA prepayments$ 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 endedSeptember 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 endedSeptember 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 endedSeptember 30, 2022 and 2021, respectively. The change was primarily driven by: •the issuance of$1.250 billion principal amount ofVistra Operations senior unsecured notes inMay 2021 ; •$1.590 billion in cash paid for share repurchases in 2022, including$114 million of unsettled share repurchases accrued as ofDecember 31, 2021 and excluding$18 million of unsettled share repurchases accrued as ofSeptember 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 ofVistra Operations senior secured notes inMay 2022 ; and •net borrowings of$625 million under the accounts receivable financing facilities in 2022 compared to net borrowings of$175 million in 2021. 76 -------------------------------------------------------------------------------- Table of Contents 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 2021 Change
Cash and cash equivalents $ 535 $ 1,325 $ (790)
Vistra Operations Credit Facilities - Revolving
Credit Facility 1,202 1,254 (52)
Vistra Operations - Commodity-Linked Facility (a) 1,701 - 1,701
Total available liquidity (b) $ 3,438 ____________
(a)As ofSeptember 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 inOctober 2022 , decreasing the aggregate commitments to$1.35 billion and extending the term toOctober 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 endedSeptember 30, 2022 was primarily driven by$1.5 billion principal amount ofVistra Operations senior secured notes issued,$1.701 billion in available capacity under the Commodity-Linked Facility under the aggregate commitments in effect as ofSeptember 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 ofNovember 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.
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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
•$3.066 billion in cash has been posted with counterparties as compared to$1.263 billion posted atDecember 31, 2021 ; •$37 million in cash has been received from counterparties as compared to$39 million received atDecember 31, 2021 ; •$2.635 billion in letters of credit have been posted with counterparties as compared to$1.558 billion posted atDecember 31, 2021 ; and •$88 million in letters of credit have been received from counterparties as compared to$35 million received atDecember 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 toVistra'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 endedSeptember 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 ofSeptember 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. InSeptember 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 ofVistra 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. 78 -------------------------------------------------------------------------------- Table of Contents 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, atSeptember 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 atSeptember 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 byVistra 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 atSeptember 30, 2022 . Each ofVistra 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 byVistra 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 withVistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled. Under theVistra Operations Senior Unsecured Indentures and theVistra Operations Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money byVistra 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 theVistra 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, ifTXU Energy , Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries ofVistra 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 ofTXU 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 byVistra 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. 79 -------------------------------------------------------------------------------- Table of Contents Under the Commodity-Linked Facility, a default under any document evidencing indebtedness for borrowed money byVistra 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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