# Vistra Corp.: Form 10-Q for the period ended Sep 30, 2023

- Company: [Vistra Corp.](/companies/vst.md) (CIK 1692819)
- Form: 10-Q
- Filed: 2023-11-07
- Accepted by EDGAR: Nov 7, 2023, 15:00 ET
- Period: 2023-09-30
- Accession: 0001628280-23-037205
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1692819/000162828023037205/vistra-20230930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1692819/000162828023037205/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $4.79bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $10.92bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Selling, general and administrative | 3 months, 2023-07-01 to 2023-09-30 | $357.0m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Selling, general and administrative | 9 months, 2023-01-01 to 2023-09-30 | $953.0m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | $834.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | $2.56bn | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-07-01 to 2023-09-30 | $143.0m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2023-01-01 to 2023-09-30 | $450.0m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | $169.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | $470.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | $502.0m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $1.68bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-07-01 to 2023-09-30 | $1.25 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2023-01-01 to 2023-09-30 | $4.13 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-07-01 to 2023-09-30 | $1.27 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2023-01-01 to 2023-09-30 | $4.18 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-07-01 to 2023-09-30 | 372,149,099 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2023-01-01 to 2023-09-30 | 379,102,358 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $4.57bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 9 months, 2023-01-01 to 2023-09-30 | $1.26bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 9 months, 2023-01-01 to 2023-09-30 | $228.0m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 9 months, 2023-01-01 to 2023-09-30 | $866.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-09-30 | $3.17bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $10.70bn | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $31.95bn | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $8.75bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $26.42bn | us-gaap:Liabilities |
| Short-term borrowings | at 2023-09-30 | $0 | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2023-09-30 | $5.51bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 90,674 characters.

*The discussion below, as well as other portions of this quarterly report on Form 10-Q, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as may," "will," "should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and Part I, Item 1A "Risk Factors" in the Company's 2022 Form 10-K and any updates contained herein. Forward-looking statements reflect the information only as of the date on which they are made. The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information. If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements. This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the condensed consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q for the three and nine months ended September 30, 2023. This discussion should be read in conjunction with those condensed consolidated financial statements and the related notes and is qualified by reference to them.*

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2023 and 2022 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

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

### Critical Accounting Policies and Estimates

The Company's discussion and analysis of its financial position and results of operations is based upon its condensed consolidated financial statements. The preparation of these condensed consolidated financial statements requires estimation and judgment that affect the reported amounts of revenue, expenses, assets and liabilities. The Company bases its estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the accounting for assets and liabilities that are not readily apparent from other sources. If the estimates differ materially from actual results, the impact on the condensed consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2022 Form 10-K.

### Business

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

### Operating Segments

Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 18 to the Financial Statements for further information concerning our reportable business segments.

### Significant Activities and Events and Items Influencing Future Performance

#### Transaction Agreement

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

#### Climate Change, Investments in Clean Energy and CO2 Reductions

*Environmental Regulations —* We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. Environmental regulations could have a material impact on our business, such as certain corrective action measures that may be required under the CCR rule and the ELG rule (see Note 13 to the Financial Statements). However, such rules and the regulatory environment are continuing to evolve and change, and we cannot predict the ultimate effect that such changes may have on our business.

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

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

*Solar Generation and Energy Storage Projects —*

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

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

*CO2 Reductions —* In June 2022, September 2022 and January 2023, we retired the Zimmer coal-fueled generation facility, the Joppa generation facilities and the Edwards coal-fueled generation facility, respectively. See Note 4 to the Financial Statements for a summary of our planned generation retirements.

#### Comanche Peak Nuclear Plant License Renewal

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

#### Inflation Reduction Act of 2022

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% CAMT on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months. The excise tax on stock repurchases is not expected to have a material impact on our financial statements. Vistra is not subject to the CAMT in the 2023 tax year since it only applies to corporations that have a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect and for estimating the TRA liability. See Note 1 for our accounting policy related to refundable and transferable PTCs and ITCs.

#### Macroeconomic Conditions

With forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods. As of September 30, 2023, we have hedged approximately 90% of our expected generation volumes on average for the balance of 2023 through 2025 (with approximately 99% hedged for the balance of 2023 and approximately 97% hedged for 2024).

The industry continues to experience supply chain constraints that have reduced the availability and increased the costs of certain fuels, reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased the lead time to procure certain materials necessary to maintain our natural gas, nuclear and coal fleet. We are proactively managing the increased costs of materials and supply chain disruptions and continuing to prudently re-evaluate the business cases and timing of our planned development projects, which has resulted in a deferral of some of our planned capital spend for our renewables projects. In addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the impact of the IRA. The inflationary environment experienced throughout 2022 drove increases in interest rates, resulting in increased expected refinancing or borrowing costs, including project financing for our development projects and refinancing expected in connection with debt due in 2024.

#### Winter Storm Uri

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

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

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

#### Dividend Program

In November 2018, we announced that the Board had adopted a dividend program, which we initiated in the first quarter of 2019. See Note 14 to the Financial Statements for more information about our dividend program.

#### Share Repurchase Program

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

|  | $4.25 Billion Board Authorization Total Number of Shares Repurchased | Average Price Paid Per Share | Amount Paid for Shares Repurchased | Amount Available for Additional Repurchases at the End of the Period |
| --- | ---: | ---: | ---: | ---: |
| Three Months Ended March 31, 2023 | 13,308,465 | $23.11 | $308 |  |
| Three Months Ended June 30, 2023 | 10,144,891 | 24.39 | 247 |  |
| Three Months Ended September 30, 2023 | 10,550,307 | 30.36 | 320 |  |
| Nine Months Ended September 30, 2023 | 34,003,663 | $25.74 | $875 | $1,130 |
| October 1, 2023 through November 2, 2023 | 4,547,264 | 32.27 | 147 |  |
| January 1, 2023 through November 2, 2023 | 38,550,927 | $26.51 | $1,022 | $983 |

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

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

#### Collateral Financing Agreement With Affiliate

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

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

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

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

#### Debt Activity

We remain committed to a strong balance sheet and have continued to state our objective to reduce our consolidated net leverage. We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities. See Note 12 to the Financial Statements for details of our debt activity, including the April 2023 Amendment to the Vistra Operations Credit Agreement, and Note 10 to the Financial Statements for details of our accounts receivable financing.

#### Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of September 30, 2023 were as follows:

| Nuclear/Renewable/Coal Generation: | Balance of 2023 | 2024 |
| --- | ---: | ---: |
| Texas | 99% | 98% |
| Sunset | 100% | 89% |
| Gas Generation: |  |  |
| Texas | 98% | 93% |
| East | 100% | 95% |
| West | 100% | 100% |

The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MMBtu/MWh) on realized pre-tax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of September 30, 2023.

| Texas: | Balance of 2023 | 2024 |
| --- | ---: | ---: |
| Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price | $— | $3 |
| Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price | $— | $(2) |
| Gas Generation: $1.00/MWh increase in spark spread | $— | $4 |
| Gas Generation: $1.00/MWh decrease in spark spread | $— | $(3) |
| Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price | $(2) | $(10) |
| Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price | $— | $9 |
| East: |  |  |
| Gas Generation: $1.00/MWh increase in spark spread | $— | $4 |
| Gas Generation: $1.00/MWh decrease in spark spread | $— | $(2) |
| Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price | $1 | $(3) |
| Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price | $(1) | $3 |
| West: |  |  |
| Gas Generation: $1.00/MWh increase in spark spread | $— | $— |
| Gas Generation: $1.00/MWh decrease in spark spread | $— | $— |
| Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price | $— | $2 |
| Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price | $— | $(2) |
| Sunset: |  |  |
| Coal Generation: $2.50/MWh increase in power price | $— | $6 |
| Coal Generation: $2.50/MWh decrease in power price | $1 | $(7) |
| Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price | $— | $(1) |
| Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price | $— | $1 |

62

### RESULTS OF OPERATIONS

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

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

|  | Three Months Ended September 30, 2023 | 2022 | Favorable (Unfavorable) $ Change 2023 | Nine Months Ended September 30, 2022 |  | Favorable (Unfavorable) $ Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $4,086 | $5,146 | $(1,060) | $11,701 | $9,859 | $1,842 |
| Fuel, purchased power costs and delivery fees | (2,109) | (3,139) | 1,030 | (5,754) | (7,580) | 1,826 |
| Operating costs | (411) | (400) | (11) | (1,277) | (1,250) | (27) |
| Depreciation and amortization | (375) | (390) | 15 | (1,109) | (1,214) | 105 |
| Selling, general and administrative expenses | (357) | (323) | (34) | (953) | (894) | (59) |
| Impairment of long-lived assets | — | — | — | (49) | — | (49) |
| Operating income (loss) | 834 | 894 | (60) | 2,559 | (1,079) | 3,638 |
| Other income | 32 | 10 | 22 | 174 | 88 | 86 |
| Other deductions | (3) | (5) | 2 | (9) | (18) | 9 |
| Interest expense and related charges | (143) | (71) | (72) | (450) | (186) | (264) |
| Impacts of Tax Receivable Agreement | (49) | 86 | (135) | (128) | (29) | (99) |
| Income (loss) before income taxes | 671 | 914 | (243) | 2,146 | (1,224) | 3,370 |
| Income tax (expense) benefit | (169) | (236) | 67 | (470) | 262 | (732) |
| Net income (loss) | $502 | $678 | $(176) | $1,676 | $(962) | $2,638 |

63

|  | Three Months Ended September 30, 2023 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $3,383 | $1,517 | $651 | $344 | $224 | $— | $(2,033) | $4,086 |
| Fuel, purchased power costs and delivery fees | (2,837) | (707) | (376) | (46) | (176) | (1) | 2,034 | (2,109) |
| Operating costs | (36) | (217) | (65) | (14) | (63) | (15) | (1) | (411) |
| Depreciation and amortization | (26) | (132) | (161) | (22) | (16) | — | (18) | (375) |
| Selling, general and administrative expenses | (237) | (32) | (20) | (6) | (11) | (7) | (44) | (357) |
| Operating income (loss) | 247 | 429 | 29 | 256 | (42) | (23) | (62) | 834 |
| Other income | — | 4 | — | 8 | — | 7 | 13 | 32 |
| Other deductions | — | — | — | — | (2) | — | (1) | (3) |
| Interest expense and related charges | (2) | 5 | — | — | — | (1) | (145) | (143) |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | — | (49) | (49) |
| Income (loss) before income taxes | 245 | 438 | 29 | 264 | (44) | (17) | (244) | 671 |
| Income tax expense | — | — | — | — | — | — | (169) | (169) |
| Net income (loss) | $245 | $438 | $29 | $264 | $(44) | $(17) | $(413) | $502 |

|  | Three Months Ended September 30, 2022 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $3,258 | $3,627 | $1,126 | $236 | $253 | $95 | $(3,449) | $5,146 |
| Fuel, purchased power costs and delivery fees | (4,161) | (1,119) | (983) | (155) | (132) | (39) | 3,450 | (3,139) |
| Operating costs | (43) | (193) | (58) | (10) | (64) | (32) | — | (400) |
| Depreciation and amortization | (36) | (135) | (187) | 4 | (17) | (1) | (18) | (390) |
| Selling, general and administrative expenses | (238) | (33) | (18) | (5) | (9) | (12) | (8) | (323) |
| Operating income (loss) | (1,220) | 2,147 | (120) | 70 | 31 | 11 | (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 | 31 | 16 | (15) | 914 |
| Income tax expense | — | — | — | — | — | — | (236) | (236) |
| Net income (loss) | $(1,227) | $2,156 | $(119) | $72 | $31 | $16 | $(251) | $678 |

64

Operating income decreased $60 million to operating income of $834 million in the three months ended September 30, 2023 compared to the three months ended September 30, 2022. This decrease is primarily related to a $603 million change in unrealized mark-to-market as results for the three months ended September 30, 2023 were unfavorably impacted by $283 million in pre-tax unrealized mark-to-market losses on derivative positions due to power forward market curves moving up in Texas in the three months ended September 30, 2023 compared to $320 million in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the three months ended September 30, 2022. The unfavorable variance related to unrealized mark-to-market is offset by improved operating performance in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 driven by strong plant operating performance and higher energy margins reflecting the effectiveness of our comprehensive hedging strategy driving higher realized energy margins. Additionally, revenue net of fuel was higher in the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices in the third quarter of 2022.

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

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

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

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

65

|  | Nine Months Ended September 30, 2022 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $6,876 | $1,909 | $2,400 | $387 | $55 | $297 | $(2,065) | $9,859 |
| Fuel, purchased power costs and delivery fees | (3,913) | (2,342) | (2,524) | (279) | (313) | (275) | 2,066 | (7,580) |
| Operating costs | (111) | (602) | (189) | (32) | (191) | (125) | — | (1,250) |
| Depreciation and amortization | (109) | (404) | (545) | (26) | (49) | (29) | (52) | (1,214) |
| Selling, general and administrative expenses | (622) | (99) | (50) | (17) | (26) | (33) | (47) | (894) |
| Operating income (loss) | 2,121 | (1,538) | (908) | 33 | (524) | (165) | (98) | (1,079) |
| Other 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 | (525) | (154) | (315) | (1,224) |
| Income tax benefit | — | — | — | — | — | — | 262 | 262 |
| Net income (loss) | $2,099 | $(1,455) | $(910) | $36 | $(525) | $(154) | $(53) | $(962) |

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

For the nine months ended September 30, 2023, other income totaled $174 million driven by a gain of $89 million from the sale of property in Freestone County, Texas. For the nine months ended September 30, 2022, other income totaled $88 million driven by insurance proceeds of $63 million which primarily consists of business interruption claim proceeds. See Note 19 to the Financial Statements.

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

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

For the nine months ended September 30, 2023, income tax expense totaled $470 million and the effective tax rate was 21.9%. For the nine months ended September 30, 2022, income tax benefit totaled $262 million, and the effective tax rate was 21.4%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

### Discussion of Adjusted EBITDA

***Non-GAAP Measures —*** In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

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

Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.

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

### Adjusted EBITDA — Three and Nine Months Ended September 30, 2023 Compared to Three and Nine Months Ended September 30, 2022

|  | Three Months Ended September 30, 2023 | 2022 | Favorable (Unfavorable) $ Change 2023 | Nine Months Ended September 30, 2022 |  | Favorable (Unfavorable) $ Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| **Net income (loss)** | $502 | $678 | $(176) | $1,676 | $(962) | $2,638 |
| Income tax expense (benefit) | 169 | 236 | (67) | 470 | (262) | 732 |
| Interest expense and related charges (a) | 143 | 71 | 72 | 450 | 186 | 264 |
| Depreciation and amortization (b) | 401 | 413 | (12) | 1,177 | 1,277 | (100) |
| **EBITDA before Adjustments** | 1,215 | 1,398 | (183) | 3,773 | 239 | 3,534 |
| Unrealized net (gain) loss resulting from commodity hedging transactions (c) | 283 | (320) | 603 | (855) | 2,027 | (2,882) |
| Impacts of Tax Receivable Agreement | 49 | (86) | 135 | 128 | 29 | 99 |
| Non-cash compensation expenses | 21 | 14 | 7 | 63 | 48 | 15 |
| Transition and merger expenses | 22 | (2) | 24 | 39 | 18 | 21 |
| Impairment of long-lived assets | — | — | — | 49 | — | 49 |
| PJM capacity performance default impacts (d) | 1 | — | 1 | 9 | — | 9 |
| Winter Storm Uri impacts (e) | (7) | (31) | 24 | (44) | (147) | 103 |
| Other, net | 5 | 8 | (3) | 6 | 44 | (38) |
| **Adjusted EBITDA** | $1,589 | $981 | $608 | $3,168 | $2,258 | $910 |

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

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

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

(d) For the three and nine months ended September 30, 2023, represents estimate of anticipated market participant defaults or settlements on initial PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott.

(e) For the three and nine months ended September 30, 2023, includes reductions to Adjusted EBITDA reflecting bill credit applications of $7 million and $46 million, respectively. For the three and nine months ended September 30, 2022, includes reductions to Adjusted EBITDA reflecting default uplift charges of zero and $56 million, respectively, attributable to ERCOT receiving payments that reduced the market wide default balance, and bill credit applications of $32 million and $98 million, respectively. In 2021, an adjustment for future bill credits was recorded related to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. These amounts reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance.

|  | Three Months Ended September 30, 2023 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Net income (loss)** | $245 | $438 | $29 | $264 | $(44) | $(17) | $(413) | $502 |
| Income tax expense | — | — | — | — | — | — | 169 | 169 |
| Interest expense and related charges (a) | 2 | (5) | — | — | — | 1 | 145 | 143 |
| Depreciation and amortization (b) | 26 | 158 | 161 | 22 | 16 | — | 18 | 401 |
| **EBITDA before Adjustments** | 273 | 591 | 190 | 286 | (28) | (16) | (81) | 1,215 |
| Unrealized net (gain) loss resulting from hedging transactions | (97) | 356 | 125 | (203) | 110 | (8) | — | 283 |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | — | 49 | 49 |
| Non-cash compensation expenses | — | — | — | — | — | — | 21 | 21 |
| Transition and merger expenses | — | — | — | — | — | — | 22 | 22 |
| PJM capacity performance default impacts (c) | — | — | (3) | — | 4 | — | — | 1 |
| Winter Storm Uri impacts (d) | (8) | 1 | — | — | — | — | — | (7) |
| Other, net | 5 | 2 | 3 | 4 | 16 | — | (25) | 5 |
| **Adjusted EBITDA** | $173 | $950 | $315 | $87 | $102 | $(24) | $(14) | $1,589 |

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

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

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

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

|  | Three Months Ended September 30, 2022 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Net income (loss)** | $(1,227) | $2,156 | $(119) | $72 | $31 | $16 | $(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) | 17 | 1 | 18 | 413 |
| **EBITDA before Adjustments** | (1,187) | 2,305 | 68 | 66 | 49 | 18 | 79 | 1,398 |
| Unrealized net (gain) loss resulting from hedging transactions | 1,203 | (1,436) | 68 | (22) | (65) | (68) | — | (320) |
| 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 | 10 | (9) | (15) | 8 |
| **Adjusted EBITDA** | $(2) | $873 | $138 | $45 | $(6) | $(59) | $(8) | $981 |

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

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

(c) Adjusted EBITDA impacts of Winter Storm Uri reflects the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri.

|  | Nine Months Ended September 30, 2023 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Net income (loss)** | $462 | $396 | $1,049 | $481 | $442 | $23 | $(1,177) | $1,676 |
| Income tax expense | — | — | 1 | — | — | — | 469 | 470 |
| Interest expense and related charges (a) | 19 | (15) | — | (8) | 2 | 4 | 448 | 450 |
| Depreciation and amortization (b) | 78 | 458 | 488 | 56 | 45 | — | 52 | 1,177 |
| **EBITDA before Adjustments** | 559 | 839 | 1,538 | 529 | 489 | 27 | (208) | 3,773 |
| Unrealized net (gain) loss resulting from hedging transactions | 114 | 703 | (1,024) | (338) | (278) | (32) | — | (855) |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | — | 128 | 128 |
| Non-cash compensation expenses | — | — | — | — | — | — | 63 | 63 |
| Transition and merger expenses | (2) | 1 | — | — | 1 | — | 39 | 39 |
| Impairment of long-lived assets | — | — | — | — | 49 | — | — | 49 |
| PJM capacity performance default impacts (c) | — | — | 3 | — | 6 | — | — | 9 |
| Winter Storm Uri impacts (d) | (46) | 2 | — | — | — | — | — | (44) |
| Other, net | 17 | (5) | 9 | 5 | 38 | (1) | (57) | 6 |
| **Adjusted EBITDA** | $642 | $1,540 | $526 | $196 | $305 | $(6) | $(35) | $3,168 |

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

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

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

(d) Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. We estimate remaining bill credit amounts to be applied in future periods are for the remainder of 2023 (approximately $6 million), 2024 (approximately $11 million) and 2025 (approximately $25 million).

|  | Nine Months Ended September 30, 2022 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Net income (loss)** | $2,099 | $(1,455) | $(910) | $36 | $(525) | $(154) | $(53) | $(962) |
| Income tax benefit | — | — | — | — | — | — | (262) | (262) |
| Interest expense and related charges (a) | 8 | (20) | 3 | (3) | 2 | 2 | 194 | 186 |
| Depreciation and amortization (b) | 109 | 467 | 545 | 26 | 49 | 29 | 52 | 1,277 |
| **EBITDA before Adjustments** | 2,216 | (1,008) | (362) | 59 | (474) | (123) | (69) | 239 |
| Unrealized net (gain) loss resulting from hedging transactions | (1,602) | 2,260 | 805 | 49 | 473 | 42 | — | 2,027 |
| 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 | 17 | 4 | (44) | 44 |
| **Adjusted EBITDA** | $564 | $1,221 | $450 | $110 | $16 | $(77) | $(26) | $2,258 |

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

(b) Includes nuclear fuel amortization of $63 million in Texas segment.

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

***Retail Segment — Three and Nine Months Ended September 30, 2023 Compared to Three and Nine Months Ended September 30, 2022***

| Operating revenues: | Three Months Ended September 30, 2023 | 2022 | Favorable (Unfavorable) Change 2023 | Nine Months Ended September 30, 2022 |  | Favorable (Unfavorable) Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Revenues in ERCOT | $2,878 | $2,422 | $456 | $6,570 | $5,887 | $683 |
| Revenues in Northeast/Midwest | 574 | 609 | (35) | 1,496 | 1,800 | (304) |
| Amortization expense | 1 | 2 | (1) | — | 1 | (1) |
| Unrealized net gains (losses) on hedging activities | (70) | 225 | (295) | 95 | (812) | 907 |
| Total operating revenues | 3,383 | 3,258 | 125 | 8,161 | 6,876 | 1,285 |
| Fuel, purchased power costs and delivery fees: |  |  |  |  |  |  |
| Purchases from affiliates | (2,201) | (2,020) | (181) | (4,799) | (4,473) | (326) |
| Unrealized net gains (losses) on hedging activities with affiliates (a) | 167 | (1,428) | 1,595 | (193) | 2,409 | (2,602) |
| Unrealized net gains (losses) on hedging activities | — | — | — | (16) | 5 | (21) |
| Delivery fees | (779) | (684) | (95) | (1,789) | (1,758) | (31) |
| Other costs | (24) | (29) | 5 | (82) | (96) | 14 |
| Total fuel, purchased power costs and delivery fees | (2,837) | (4,161) | 1,324 | (6,879) | (3,913) | (2,966) |
| **Net income (loss)** | **$245** | **$(1,227)** | **$1,472** | **$462** | **$2,099** | **$(1,637)** |
| **Adjusted EBITDA** | **$173** | **$(2)** | **$175** | **$642** | **$564** | **$78** |
| **Retail sales volumes (GWh):** |  |  |  |  |  |  |
| Retail electricity sales volumes: |  |  |  |  |  |  |
| Sales volumes in ERCOT | 22,643 | 19,720 | 2,923 | 54,711 | 50,756 | 3,955 |
| Sales volumes in Northeast/Midwest | 7,935 | 8,729 | (794) | 19,965 | 26,161 | (6,196) |
| Total retail electricity sales volumes | 30,578 | 28,449 | 2,129 | 74,676 | 76,917 | (2,241) |
| **Weather (North Texas average) - percent of normal (b):** |  |  |  |  |  |  |
| Cooling degree days | 121.7% | 108.1% |  | 115.2% | 112.1% |  |
| Heating degree days | —% | —% |  | 81.7% | 111.8% |  |

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the three and nine months ended September 30, 2023 compared to the three and nine months ended September 30, 2022.

|  | Three Months Ended September 30, 2023 Compared to 2022 | Nine Months Ended September 30, 2023 Compared to 2022 |
| --- | ---: | ---: |
| Higher margins driven by seasonality of power costs | $148 | $154 |
| Winter Storm Uri impact, including bill credits | 24 | 52 |
| Lower margins due to mild weather in 2023 | — | (107) |
| Lower bad debt expense | 11 | 5 |
| Other driven by higher selling costs and revenue-based taxes due to higher revenues in ERCOT | (8) | (26) |
| **Change in Adjusted EBITDA** | **$175** | **$78** |
| Change in unrealized net gains/(losses) on hedging activities | 1,300 | (1,716) |
| Bill credits and other costs related to Winter Storm Uri | (24) | (49) |
| Decrease in depreciation and amortization expenses | 10 | 31 |
| Change in other expenses | 11 | 19 |
| **Change in Net income (loss)** | **$1,472** | **$(1,637)** |

73

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

| Operating revenues: | Three Months Ended September 30, Texas 2023 | 2022 | East 2023 | 2022 | West 2023 | 2022 | Sunset 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Electricity sales | $214 | $700 | $341 | $757 | $167 | $178 | $241 | $91 |
| Capacity revenue from ISO/RTO | — | — | 12 | 14 | — | — | 8 | — |
| Sales to affiliates | 1,680 | 1,442 | 426 | 458 | — | 2 | 95 | 120 |
| Rolloff of unrealized net gains (losses) representing positions settled in the current period | 586 | 253 | 59 | 57 | — | 54 | (67) | 154 |
| Unrealized net gains (losses) on hedging activities | (888) | 19 | (106) | (240) | 176 | 1 | (43) | (230) |
| Unrealized net gains (losses) on hedging activities with affiliates | (78) | 1,213 | (81) | 80 | — | 1 | (8) | 119 |
| Other revenues | 3 | — | — | — | 1 | — | (2) | (1) |
| Operating revenues | 1,517 | 3,627 | 651 | 1,126 | 344 | 236 | 224 | 253 |
| Fuel, purchased power costs and delivery fees: |  |  |  |  |  |  |  |  |
| Fuel for generation facilities and purchased power costs | (505) | (975) | (369) | (1,006) | (72) | (120) | (183) | (153) |
| Fuel for generation facilities and purchased power costs from affiliates | 2 | (3) | (2) | 1 | — | — | — | 1 |
| Unrealized gains (losses) from hedging activities | 24 | (52) | 3 | 36 | 27 | (34) | 8 | 24 |
| Unrealized gains (losses) on hedging activities with affiliates | — | 3 | — | (1) | — | — | — | (2) |
| Ancillary and other costs | (228) | (92) | (8) | (13) | (1) | (1) | (1) | (2) |
| Fuel, purchased power costs and delivery fees | (707) | (1,119) | (376) | (983) | (46) | (155) | (176) | (132) |
| **Net income (loss)** | **$438** | **$2,156** | **$29** | **$(119)** | **$264** | **$72** | **$(44)** | **$31** |
| **Adjusted EBITDA** | **$950** | **$873** | **$315** | **$138** | **$87** | **$45** | **$102** | **$(6)** |
| **Production volumes (GWh):** |  |  |  |  |  |  |  |  |
| Natural gas facilities | 15,635 | 12,654 | 16,976 | 15,118 | 1,465 | 1,460 |  |  |
| Lignite and coal facilities | 6,743 | 6,643 |  |  |  |  | 5,038 | 5,713 |
| Nuclear facilities | 5,210 | 5,009 |  |  |  |  |  |  |
| Solar facilities | 247 | 250 |  |  |  |  |  |  |
| **Capacity factors:** |  |  |  |  |  |  |  |  |
| CCGT facilities | 77.2% | 69.6% | 69.2% | 62.6% | 65.0% | 65.0% |  |  |
| Lignite and coal facilities | 79.3% | 78.1% |  |  |  |  | 49.8% | 56.5% |
| Nuclear facilities | 98.3% | 94.5% |  |  |  |  |  |  |
| **Weather - percent of normal (a):** |  |  |  |  |  |  |  |  |
| Cooling degree days | 120.5% | 105.2% | 96.7% | 111.2% | 93.2% | 112.9% | 111.5% | 107.7% |
| Heating degree days | —% | —% | 101.8% | 119.6% | —% | —% | —% | 111.3% |

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

| Market pricing | Three Months Ended September 30, 2023 |  | 2022 | Average Market On-Peak Power Prices ($MWh) (b): | Three Months Ended September 30, 2023 | 2022 |
| --- | ---: | --- | ---: | --- | ---: | ---: |
| Average ERCOT North power price ($/MWh) | $109.32 |  | $100.54 | PJM West Hub | $42.93 | $111.21 |
|  |  | AEP Dayton Hub | $40.00 | $106.07 |  |  |
| Average NYMEX Henry Hub natural gas price ($/MMBtu) | $2.58 |  | $7.96 | NYISO Zone C | $35.46 | $87.63 |
|  |  | Massachusetts Hub | $39.88 | $99.52 |  |  |
| **Average natural gas price (a):** |  |  |  | Indiana Hub | $42.99 | $109.24 |
| TetcoM3 ($/MMBtu) | $1.39 |  | $7.10 | Northern Illinois Hub | $39.36 | $100.59 |
| Algonquin Citygates ($/MMBtu) | $1.93 |  | $7.57 | CAISO NP15 | $59.65 | $105.25 |

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended September 30, 2023 compared to the three months ended September 30, 2022.

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

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

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

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

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

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

| Operating revenues: | Nine Months Ended September 30, Texas 2023 | 2022 | East 2023 | 2022 | West 2023 | 2022 | Sunset 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Electricity sales | $405 | $1,302 | $1,051 | $1,975 | $497 | $405 | $612 | $253 |
| Capacity revenue from ISO/RTO | — | — | 42 | 4 | — | — | 35 | 56 |
| Sales to affiliates | 3,334 | 2,746 | 1,197 | 1,371 | 9 | 5 | 259 | 353 |
| Rolloff of unrealized net gains (losses) representing positions settled in the current period | 865 | 441 | 482 | (12) | 29 | 52 | (130) | 230 |
| Unrealized net gains (losses) on hedging activities | (1,163) | (865) | 95 | (359) | 267 | (79) | 448 | (726) |
| Unrealized net gains (losses) on hedging activities with affiliates | (388) | (1,715) | 440 | (580) | (3) | 4 | 144 | (105) |
| Other revenues | 8 | — | (2) | 1 | — | — | (2) | (6) |
| Operating revenues | 3,061 | 1,909 | 3,305 | 2,400 | 799 | 387 | 1,366 | 55 |
| Fuel, purchased power costs and delivery fees: |  |  |  |  |  |  |  |  |
| Fuel for generation facilities and purchased power costs | (1,170) | (1,967) | (1,458) | (2,644) | (269) | (249) | (412) | (436) |
| Fuel for generation facilities and purchased power costs from affiliates | 10 | (6) | (10) | 2 | — | — | — | 2 |
| Unrealized gains (losses) from hedging activities | (17) | (119) | 7 | 146 | 45 | (26) | (184) | 126 |
| Unrealized gains (losses) from hedging activities with affiliates | — | (2) | — | — | — | — | — | 2 |
| Ancillary and other costs | (369) | (248) | (33) | (28) | (2) | (4) | (3) | (7) |
| Fuel, purchased power costs and delivery fees | (1,546) | (2,342) | (1,494) | (2,524) | (226) | (279) | (599) | (313) |
| **Net income (loss)** | **$396** | **$(1,455)** | **$1,049** | **$(910)** | **$481** | **$36** | **$442** | **$(525)** |
| **Adjusted EBITDA** | **$1,540** | **$1,221** | **$526** | **$450** | **$196** | **$110** | **$305** | **$16** |
| **Production volumes (GWh):** |  |  |  |  |  |  |  |  |
| Natural gas facilities | 32,809 | 26,304 | 45,470 | 40,872 | 3,741 | 3,525 |  |  |
| Lignite and coal facilities | 17,903 | 18,376 |  |  |  |  | 11,355 | 16,236 |
| Nuclear facilities | 14,471 | 14,369 |  |  |  |  |  |  |
| Solar facilities | 638 | 679 |  |  |  |  |  |  |
| **Capacity factors:** |  |  |  |  |  |  |  |  |
| CCGT facilities | 57.1% | 49.3% | 62.8% | 57.4% | 55.9% | 52.3% |  |  |
| Lignite and coal facilities | 71.0% | 72.9% |  |  |  |  | 37.9% | 54.1% |
| Nuclear facilities | 92.0% | 91.4% |  |  |  |  |  |  |
| **Weather - percent of normal (a):** |  |  |  |  |  |  |  |  |
| Cooling degree days | 113.5% | 110.4% | 89.3% | 108.2% | 78.4% | 111.4% | 110.4% | 113.9% |

76

|  | Nine Months Ended September 30, Texas 2023 | 2022 | East 2023 | 2022 | West 2023 | 2022 | Sunset 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Heating degree days | 81.5% | 129.4% | 85.3% | 98.9% | 154.3% | 95.4% | 85.5% | 101.6% |

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

| Market pricing | Nine Months Ended September 30, 2023 |  | 2022 | Average Market On-Peak Power Prices ($MWh) (b): | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | --- | ---: | --- | ---: | ---: |
| Average ERCOT North power price ($/MWh) | $56.26 |  | $67.08 | PJM West Hub | $38.20 | $87.53 |
|  |  | AEP Dayton Hub | $36.16 | $83.66 |  |  |
| Average NYMEX Henry Hub natural gas price ($/MMBtu) | $2.46 |  | $6.66 | NYISO Zone C | $30.12 | $70.09 |
|  |  | Massachusetts Hub | $41.49 | $95.91 |  |  |
| **Average natural gas price (a):** |  |  |  | Indiana Hub | $39.49 | $86.77 |
| TetcoM3 ($/MMBtu) | $1.94 |  | $6.87 | Northern Illinois Hub | $32.96 | $76.68 |
| Algonquin Citygates ($/MMBtu) | $3.02 |  | $9.46 | CAISO NP15 | $64.35 | $75.19 |

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022.

|  | Nine Months Ended September 30, 2023 Compared to 2022 Texas | East | West | Sunset |
| --- | ---: | ---: | ---: | ---: |
| Favorable change in revenue net of fuel | $447 | $111 | $78 | $303 |
| Unfavorable change in other operating costs | (79) | (28) | (11) | (4) |
| Favorable/(unfavorable) change in selling, general and administrative expenses | 5 | (7) | 2 | (7) |
| Other | (54) | — | 17 | (3) |
| **Change in Adjusted EBITDA** | **$319** | **$76** | **$86** | **$289** |
| Favorable/(unfavorable) change in depreciation and amortization | 9 | 57 | (30) | 4 |
| Change in unrealized net gains on hedging activities | 1,557 | 1,829 | 387 | 751 |
| Impairment of long-lived assets | — | — | — | (49) |
| PJM capacity performance default impacts | — | (3) | — | (6) |
| Winter Storm Uri impact (ERCOT default uplift) | (54) | — | — | — |
| Other (including interest expenses) | 20 | — | 2 | (22) |
| **Change in Net income** | **$1,851** | **$1,959** | **$445** | **$967** |

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

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

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

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

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

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

|  | Three Months Ended September 30, 2023 | 2022 | Favorable (Unfavorable) Change 2023 | Nine Months Ended September 30, 2022 |  | Favorable (Unfavorable) Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $— | $95 | $(95) | $— | $297 | $(297) |
| Fuel, purchased power costs and delivery fees | (1) | (39) | 38 | (2) | (275) | 273 |
| Operating costs | $(15) | $(32) | $17 | $(52) | $(125) | $73 |
| Depreciation and amortization | — | (1) | 1 | — | (29) | 29 |
| Selling, general and administrative expenses | (7) | (12) | 5 | (24) | (33) | 9 |
| Operating loss | (23) | 11 | (34) | (78) | (165) | 87 |
| Other income | 7 | 6 | 1 | 105 | 14 | 91 |
| Other deductions | — | — | — | — | (1) | 1 |
| Interest expense and related charges | (1) | (1) | — | (4) | (2) | (2) |
| Income (loss) before income taxes | (17) | 16 | (33) | 23 | (154) | 177 |
| **Net income (loss)** | **$(17)** | **$16** | **$(33)** | **$23** | **$(154)** | **$177** |
| **Adjusted EBITDA** | **$(24)** | **$(59)** | **$35** | **$(6)** | **$(77)** | **$71** |
| **Production volumes (GWh)** | — | 1,449 | (1,449) | — | 8,653 | (8,653) |

For the three and nine months ended September 30, 2022, results and volumes for the Asset Closure segment include those from Edwards generation plant that we retired on January 1, 2023, and include unrealized hedging gains related to coal and power derivatives of $59 million and $17 million in the three and nine months ended September 30, 2022, respectively. Operating costs for the three and nine months ended September 30, 2023 and 2022 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. Other income for the nine months ended September 30, 2023, includes a gain of $89 million from the sale of property in Freestone County, Texas. Results were also impacted in the three and nine months ended September 30, 2023 compared to the three and nine months ended September 30, 2022 by the retirements of the Zimmer, Joppa and Edwards generation plants on June 1, 2022, September 1, 2022 and January 1, 2023, respectively.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2023 and 2022. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $855 million in unrealized net gains and $2.027 billion in unrealized net losses for the nine months ended September 30, 2023 and 2022, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

|  | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: |
| Commodity contract net liability at beginning of period | $(3,148) | $(866) |
| Settlements/termination of positions (a) | 1,585 | 1,166 |
| Changes in fair value of positions in the portfolio (b) | (730) | (3,193) |
| Other activity (c) | (108) | 79 |
| Commodity contract net liability at end of period | $(2,401) | $(2,814) |

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

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

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

***Maturity Table —*** The following table presents the net commodity contract liability arising from recognition of fair values as of September 30, 2023, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

| Source of fair value | Maturity dates of unrealized commodity contract net liability as of September 30, 2023 Less than 1 year | 1-3 years | 4-5 years | Excess of 5 years | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Prices actively quoted | $(414) | $(222) | $2 | $— | $(634) |
| Prices provided by other external sources | (435) | (48) | — | — | (483) |
| Prices based on models | (435) | (611) | (115) | (123) | (1,284) |
| Total | $(1,284) | $(881) | $(113) | $(123) | $(2,401) |

79

### FINANCIAL CONDITION

### Cash Flows

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

Depreciation and amortization expense reported as a reconciling adjustment in the condensed consolidated statements of cash flows exceeds the amount reported in the condensed consolidated statements of operations by $333 million and $361 million for the nine months ended September 30, 2023 and 2022, respectively. The difference represents amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other condensed consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.

*Investing Cash Flows —* Cash used in investing activities totaled $1.382 billion and $886 million for the nine months ended September 30, 2023 and 2022, respectively. The increase of $496 million was driven by (a) a $353 million increase in capital expenditures due primarily to continued development of our solar and energy storage generation facilities (see Note 3 to the Financial Statements) and (b) $218 million in net purchases of environmental allowances in the nine months ended September 30, 2023 compared to $15 million in net sales in the nine months ended September 30, 2022, partially offset by $90 million in higher proceeds from the sale of assets driven by our sale of property in Freestone County, Texas in 2023.

|  | Nine Months Ended September 30, 2023 | 2022 | Increase (Decrease) |
| --- | ---: | ---: | ---: |
| Capital expenditures, including LTSA prepayments | $(575) | $(471) | $(104) |
| Nuclear fuel purchases | (174) | (173) | (1) |
| Growth and development expenditures | (513) | (265) | (248) |
| Total capital expenditures | (1,262) | (909) | (353) |
| Net sales (purchases) of environmental allowances | (218) | 15 | (233) |
| Net investments in nuclear decommissioning trust fund securities | (17) | (18) | 1 |
| Proceeds from sales of assets | 111 | 21 | 90 |
| Other investing activity | 4 | 5 | (1) |
| Cash used in investing activities | $(1,382) | $(886) | $(496) |

80

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

|  | Nine Months Ended September 30, 2023 | 2022 | Increase (Decrease) |
| --- | ---: | ---: | ---: |
| Share repurchases | $(866) | $(1,590) | $724 |
| Issuances of senior notes (see Note 12) | 1,750 | 1,498 | 252 |
| Net long-term borrowings (repayments), including the forward capacity agreements | (21) | (232) | 211 |
| Net short-term borrowings (repayments) | (650) | — | (650) |
| Net borrowings (repayments) under the accounts receivable financing facilities | (425) | 625 | (1,050) |
| Dividends paid to common stockholders | (228) | (227) | (1) |
| Dividends paid to preferred stockholders | (75) | (76) | 1 |
| Other financing activity | 25 | 5 | 20 |
| Cash provided by (used in) financing activities | $(490) | $3 | $(493) |

### Debt Activity

In May 2024 and July 2024, $400 million of 4.875% Senior Secured Notes and $1.5 billion of 3.550% Senior Secured Notes, respectively, will reach maturity. We plan to fund these upcoming principal payments using a combination of cash on hand and new debt issuances. Increases in interest rates will likely result in increased borrowing costs. See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 12 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

### Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2023:

|  | September 30, 2023 | December 31, 2022 | Change |
| --- | ---: | ---: | ---: |
| Cash and cash equivalents (a) | $3,170 | $455 | $2,715 |
| Vistra Operations Credit Facilities — Revolving Credit Facility (b) | 849 | 1,236 | (387) |
| Vistra Operations — Commodity-Linked Facility (c) | 401 | 808 | (407) |
| Total available liquidity (d)(e) | $4,420 | $2,499 | $1,921 |

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

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

(c) As of both September 30, 2023 and December 31, 2022, the borrowing bases are less than the facility limit of $1.35 billion. As of September 30, 2023, available capacity reflects the borrowing base of $401 million and no cash borrowings. As of December 31, 2022, available capacity reflects the borrowing base of $1.208 billion less $400 million in cash borrowings. The reduction in the borrowing base is due, in part, to the expiration of certain deemed 2023 hedges and would increase in size in a rising commodity price environment in accordance with the terms of the Commodity-Linked Facility. The Commodity-Linked Facility was amended in October 2023, increasing the aggregate commitments to $1.575 billion and extending the term to October 2024. The deemed hedge portfolio was also updated to reflect current hedge positions, including the addition of the 2025 deemed hedges, resulting in an increase of the borrowing base to $1.233 billion as of October 3, 2023.

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

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

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

### Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 11 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 12 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

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

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

- $1.312 billion in cash or Eligible Assets have been posted with counterparties as compared to $3.137 billion posted as of December 31, 2022;
- $50 million in cash has been received from counterparties as compared to $39 million received as of December 31, 2022;
- $2.778 billion in letters of credit have been posted with counterparties as compared to $2.314 billion posted as of December 31, 2022; and
- $45 million in letters of credit have been received from counterparties as compared to $74 million received as of December 31, 2022.

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

### Income Tax Payments

In the next 12 months, we do not expect to make federal income tax payments due to Vistra's NOL carryforwards. We expect to make approximately $34 million in state income tax payments, offset by $12 million in state tax refunds, and $10 million in TRA payments in the next 12 months.

For the nine months ended September 30, 2023, there were no federal income tax payments, $31 million in state income tax payments, $12 million in state income tax refunds and no TRA payments.

### Financial Covenants

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is in effect), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). As of September 30, 2023, we were in compliance with the Vistra Operations Credit Agreement and Secured LOC Facilities financial covenants. Although the period ended September 30, 2023 was not a compliance period for the Vistra Operations Commodity-Linked Credit Agreement, we would have been in compliance with this financial covenant if it was required to be tested at such time.

See Note 12 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

### Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of September 30, 2023, Vistra has posted letters of credit in the amount of $91 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $900 million in the form of letters of credit, $30 million in the form of a surety bond and $2 million of cash as of September 30, 2023 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

### Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.493 billion and zero, respectively, as of September 30, 2023.

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

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

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

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

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

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

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

### Guarantees

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

### COMMITMENTS AND CONTINGENCIES

See Note 13 to the Financial Statements for discussion of commitments and contingencies.

### CHANGES IN ACCOUNTING STANDARDS

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

## Market risk

As filed, 22,157 characters.

Market risk is the risk that in the normal course of business we may experience a loss in value because of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by several factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

### Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by our treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and portfolio valuation and reporting, including mark-to-market, VaR and other risk measurement metrics.

Vistra has a risk management organization that enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.

### Commodity Price Risk

Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices.

In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

***VaR Methodology —*** A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period (*i.e.*, the time necessary for management action, such as to liquidate positions) and (iii) historical estimates of volatility and correlation data. The table below details a VaR measure related to various portfolios of contracts.

***VaR for Underlying Generation Assets and Energy-Related Contracts —*** This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level and an assumed holding period of 60 days. The forward period covered by this calculation includes the current and subsequent calendar year at the time of calculation.

|  | Nine Months Ended September 30, 2023 | Year Ended December 31, 2022 |
| --- | ---: | ---: |
| Month-end average VaR | $210 | $489 |
| Month-end high VaR | $423 | $686 |
| Month-end low VaR | $127 | $283 |

The month-end high VaR risk measure in 2023 is currently lower than the prior year due to lower prices and higher hedge levels.

### Interest Rate Risk

As of September 30, 2023, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $2 million taking into account the interest rate swaps discussed in Note 12 to Financial Statements.

### Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 16 to the Financial Statements for further discussion of this exposure.

***Credit Exposure —*** Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $2.264 billion as of September 30, 2023.

As of September 30, 2023, Retail segment credit exposure totaled approximately $1.701 billion, including $1.666 billion of trade accounts receivable and $35 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled $52 million, resulting in a net exposure of $1.649 billion. Allowances for uncollectible accounts receivable are established for the expected loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

As of September 30, 2023, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled $563 million including $460 million related to derivative assets and $103 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts.

Including collateral posted to us by counterparties, our net Texas, East, Sunset and Asset Closure segments credit exposure was $542 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of September 30, 2023. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.

|  | Exposure Before Credit Collateral | Credit Collateral | Net Exposure |
| --- | ---: | ---: | ---: |
| Investment grade | $503 | $17 | $486 |
| Below investment grade or no rating | 60 | 4 | 56 |
| Totals | $563 | $21 | $542 |

86

Significant (*i.e.*, 10% or greater) concentration of credit exposure exists with three counterparties, which represented an aggregate $304 million, or 56%, of our total net exposure as of September 30, 2023. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, the counterparties' market role and deemed creditworthiness and the importance of our business relationship with the counterparty. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us.

Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.

### FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "may," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under Part II, Item 1A *Risk Factors* and Part I, Item 2 *Management's Discussion and Analysis of Financial Condition and Results of Operations* in this quarterly report on Form 10-Q and the following important factors, among others, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:

- our ability to consummate the acquisition of Energy Harbor;
- the actions and decisions of judicial and regulatory authorities;
- prohibitions and other restrictions on our operations due to the terms of our agreements;
- prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the MSHA and the CFTC, with respect to, among other things:
- allowed prices;
- industry, market and rate structure;
- purchased power and recovery of investments;
- operations of nuclear generation facilities;
- operations of fossil-fueled generation facilities;
- operations of mines;
- acquisition and disposal of assets and facilities;
- development, construction and operation of facilities;
- decommissioning costs;
- present or prospective wholesale and retail competition;
- changes in federal, state and local tax laws, rates and policies, including additional regulation, interpretations, amendments, or technical corrections to The Tax Cuts and Jobs Act of 2017 and/or the IRA;
- changes in and compliance with environmental and safety laws and policies, including the Coal Combustion Residuals Rule, National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and GHG and other climate change initiatives, and
- clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;
- expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise negatively impact our financial results or stock price;
- legal and administrative proceedings and settlements;
- general industry trends;
- economic conditions, including the impact of any inflationary period, recession or economic downturn;
- investor sentiment relating to climate change and utilization of fossil fuels in connection with power generation could reduce demand for, or increase potential volatility in the market price of, our common stock;
- the severity, magnitude and duration of pandemics, including the COVID-19 pandemic, and the resulting effects on our results of operations, financial condition and cash flows;
- the severity, magnitude and duration of extreme weather events, drought and limitations on access to water, and other weather conditions and natural phenomena, contingencies and uncertainties relating thereto, most of which are difficult to predict and many of which are beyond our control, and the resulting effects on our results of operations, financial condition and cash flows;
- acts of sabotage, geopolitical conflicts, wars, or terrorist, cybersecurity, cybercriminal, or cyber-espionage threats or activities;
- risk of contract performance claims by us or our counterparties, and risks of, or costs associated with, pursuing or defending such claims;
- our ability to collect trade receivables from counterparties in the amount or at the time expected, if at all;
- our ability to attract, retain and profitably serve customers;
- restrictions on or prohibitions of competitive retail pricing or direct-selling businesses;
- adverse publicity associated with our retail products or direct selling businesses, including our ability to address the marketplace and regulators regarding our compliance with applicable laws;
- changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
- changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
- sufficiency of, access to, and costs associated with coal, fuel oil, natural gas, and uranium inventories and transportation and storage thereof;
- changes in the ability of counterparties and suppliers to provide or deliver commodities, materials, or services as needed;
- beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;
- the effects of, or changes to, market design and the power, ancillary services and capacity procurement processes in the markets in which we operate;
- changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;
- our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
- population growth or decline, or changes in market supply or demand and demographic patterns;
- our ability to mitigate forced outage risk, including managing risk associated with Capacity Performance in PJM and performance incentives in ISO-NE;
- efforts to identify opportunities to reduce congestion and improve busbar power prices;
- access to adequate transmission facilities to meet changing demands;
- changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
- changes in operating expenses, liquidity needs and capital expenditures;
- commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets;
- access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;
- our ability to maintain prudent financial leverage and achieve our capital allocation, performance, and cost-saving initiatives and objectives;
- our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations;
- our expectation that we will continue to pay (i) a consistent aggregate cash dividend amount to common stockholders on a quarterly basis and (ii) the applicable semiannual cash dividend to the Series A Preferred Stock and Series B Preferred Stock stockholders, respectively;
- our expectation that we will continue to make repurchases under, and the possibility that we may fail to realize the anticipated benefits of, our share repurchase program, and the possibility that the program may be suspended, discontinued or not completed prior to its termination;
- our ability to implement and successfully execute upon our strategic and growth initiatives, including the completion and integration of mergers, acquisitions and/or joint venture activity, the identification and completion of sales and divestitures activity, and the completion and commercialization of our other business development and construction projects;
- competition for new energy development and other business opportunities;
- inability of various counterparties to meet their obligations with respect to our financial instruments;
- counterparties' collateral demands and other factors affecting our liquidity position and financial condition;
- changes in technology (including large-scale electricity storage) used by and services offered by us;
- changes in electricity transmission that allow additional power generation to compete with our generation assets;
- our ability to attract and retain qualified employees;
- significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur or changes in laws or regulations relating to independent contractor status;
- changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and other postretirement employee benefits, and future funding requirements related thereto, including joint and several liability exposure under ERISA;
- hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;
- the impact of our obligations under the TRA;
- our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations performance initiatives;
- our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation obligations and the impacts thereof;
- our ability to successfully complete the integration of businesses acquired by Vistra and our ability to successfully capture the full amount of projected operational and financial synergies relating to such transactions, and
- actions by credit rating agencies.

Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.

### INDUSTRY AND MARKET INFORMATION

Certain industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of states in which we operate and NYMEX. We did not commission any of these publications, reports or other sources. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Industry publications, reports and other sources generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies, publications, reports and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this report involve risks and uncertainties and are subject to change based on various factors.

## Controls and procedures

As filed, 1,112 characters.

Vistra currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel for its electricity generation facilities. Vistra also owns or leases, and is in the process of reclaiming, two waste-to-energy surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra's mines, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95.1 to this quarterly report on Form 10-Q.

## Risk factors

As filed, 8,420 characters.

As of the date of this Quarterly Report on Form 10-Q, except as set forth below, there have been no material changes to the risk factors discussed in Part I, Item 1A *Risk Factors* in our 2022 Form 10-K. We could also be affected by additional factors that are not presently known to us or that we currently consider to be immaterial to our operations.

***The Transactions are subject to a number of conditions which, if not satisfied or waived, would delay the Transactions or adversely impact our ability to complete the Transactions on the terms set forth in the Transaction Agreement or at all.***

The completion of the Transactions is subject to the satisfaction or waiver of a number of conditions, including (a) receipt of all requisite regulatory approvals, including approvals of the NRC and the FERC, (b) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and (c) the divestment of Energy Harbor's remaining fossil assets. These closing conditions may not be fulfilled in a timely manner or at all, and, accordingly, the Transactions may not be completed.

If we are unable to complete the Transactions, we still will incur and will remain liable for significant transaction costs, including legal, accounting, advisory and other costs relating to the Transactions. Also, depending upon the reasons for not completing the Transactions, we may be required to pay Energy Harbor a termination fee of $225 million. If such a termination fee is payable, the payment could affect Vistra's share price and the overall cash flows of the Company.

***Failure to consummate the Transactions as currently contemplated or at all could adversely affect the price of Vistra's common stock and our future business and financial results.***

The completion of the Transactions is subject to the satisfaction or waiver of a number of conditions. We cannot guarantee when or if these conditions will be satisfied or that the Transactions will be successfully completed. If the Transactions are not consummated, or are consummated on different terms than as contemplated by the Transaction Agreement, we could be adversely affected and subject to a variety of risks associated with the failure to consummate the Transactions, or to consummate the Transactions as contemplated by the Transaction Agreement, including:

- our stockholders may be prevented from realizing the anticipated potential benefits of the Transactions;
- the market price of our common stock could decline significantly;
- reputational harm due to the adverse public perception of any failure to successfully complete the Transactions;
- under certain circumstances, we may be required to pay Energy Harbor a termination fee of up to $225 million or reimburse Energy Harbor's expenses up to $20 million; and
- the attention of our management and employees may be diverted from their day-to-day business and operational matters and our relationships with our customers and suppliers may be disrupted as a result of efforts relating to attempting to consummate the Transactions.

Any delay in the consummation of the Transactions, any uncertainty about the consummation of the Transactions on terms other than those contemplated by the Transaction Agreement and any failure to consummate the Transactions could adversely affect our business, financial results and common stock price.

***Following the completion of the Transactions, we may be unable to successfully integrate Energy Harbor's businesses with Vistra's nuclear and retail businesses and its Vistra Zero renewable and energy storage projects or realize the anticipated synergies and other expected benefits of the Transactions on the anticipated timeframe or at all.***

The Transactions involve the combination of Energy Harbor's nuclear and retail businesses with Vistra's nuclear and retail businesses and Vistra Zero renewables and energy storage projects under a newly-formed subsidiary holding company, Vistra Vision. This new combination expects to benefit from certain cost savings, operating efficiencies and a growing renewables and energy storage portfolio, some of which will take time to realize. We will be required to devote significant management attention and resources to the integration of our and Energy Harbor's business practices and operations into Vistra Vision. The potential difficulties we may encounter in building Vistra Vision include the following:

- the inability to successfully combine our nuclear, retail, renewables and battery storage business and Energy Harbor's nuclear and retail businesses in a manner that permits Vistra Vision to achieve the cost savings anticipated to result from the Transactions, which would result in the anticipated benefits of the Transactions not being realized in the timeframe currently anticipated or at all;
- the complexities associated with maintaining the second-largest competitive nuclear fleet in the U.S.;
- the complexities of combining two companies with different histories, geographic footprints and asset mixes;
- the complexities in combining two companies with separate technology systems;
- potential unknown liabilities and unforeseen increased expenses, delays or conditions associated with the Transactions;
- failure to perform by third-party service providers who provide key services for the combined company; and
- performance shortfalls as a result of the diversion of management’s attention caused by completing the Transactions and integrating the companies' operations.

For all these reasons, it is possible that the integration process could result in the distraction of our management, the disruption of our ongoing business or inconsistencies in operations, services, standards, controls, policies and procedures, any of which could adversely affect our ability to maintain relationships with operators, vendors and employees, to achieve the anticipated benefits of the Transactions, or could otherwise materially and adversely affect its business and financial results.

***In consummating the Transactions, Vistra Operations will take on a significant amount of indebtedness. As a result, it may be more difficult for Vistra Operations to pay or refinance its debts or take other actions, and Vistra Operations may need to divert its cash flow from operations (including cash flow from the new Vistra Vision entity) to debt service payments.***

Vistra Operations will have significant indebtedness following completion of the Transactions. Initially a substantial portion of such indebtedness will be subject to rising changes in interest rates. In addition, subject to the limits contained in the documents governing such indebtedness, Vistra Operations may be able to incur significant additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions, or for other purposes. If the combined company does so, the risks related to its high level of debt could intensify. The amount of such indebtedness could have material adverse consequences for Vistra Operations, including:

- hindering its ability to adjust to changing market, industry or economic conditions;
- limiting its ability to access the capital markets to raise additional equity or refinance maturing debt on favorable terms or to fund future working capital, capital expenditures, acquisitions or emerging businesses or other general corporate purposes;
- limiting the amount of free cash flow available for future operations, acquisitions, dividends, stock repurchases or other uses;
- making it more vulnerable to economic or industry downturns, including interest rate increases; and
- placing it at a competitive disadvantage compared to less leveraged competitors.

Moreover, to respond to competitive challenges, Vistra Operations may be required to raise significant additional capital to execute its business strategy. Vistra Operations' ability to arrange additional financing will depend on, among other factors, its financial position and performance, as well as prevailing market conditions and other factors beyond its control. Even if Vistra Operations is able to obtain additional financing, its credit ratings could be adversely affected, which could raise its borrowing costs and limit its future access to capital and its ability to satisfy its obligations under its indebtedness.

Filed Nov 7, 2023.
Source: SEC EDGAR, the filing index for accession 0001628280-23-037205. Last ingested by Listed: Oct 24, 2026, 15:07 ET. No prices; not investment advice.