# Vistra Corp.: Form 10-Q for the period ended Mar 31, 2024

- Company: [Vistra Corp.](/companies/vst.md) (CIK 1692819)
- Form: 10-Q
- Filed: 2024-05-10
- Accepted by EDGAR: May 9, 2024, 18:49 ET
- Period: 2024-03-31
- Accession: 0001692819-24-000033
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1692819/000169281924000033/vistra-20240331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1692819/000169281924000033/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-01-01 to 2024-03-31 | $3.16bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Selling, general and administrative | 3 months, 2024-01-01 to 2024-03-31 | $351.0m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2024-01-01 to 2024-03-31 | $86.0m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-01-01 to 2024-03-31 | $170.0m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-01-01 to 2024-03-31 | −$20.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-01-01 to 2024-03-31 | −$35.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-01-01 to 2024-03-31 | −$0.24 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-01-01 to 2024-03-31 | −$0.24 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-01-01 to 2024-03-31 | 348,966,197 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2024-01-01 to 2024-03-31 | $312.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2024-01-01 to 2024-03-31 | $465.0m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 3 months, 2024-01-01 to 2024-03-31 | $77.0m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 3 months, 2024-01-01 to 2024-03-31 | $291.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2024-03-31 | $1.07bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-03-31 | $9.43bn | us-gaap:AssetsCurrent |
| Total assets | at 2024-03-31 | $38.18bn | us-gaap:Assets |
| Current liabilities | at 2024-03-31 | $8.78bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-03-31 | $30.89bn | us-gaap:Liabilities |
| Short-term borrowings | at 2024-03-31 | $500.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2024-03-31 | $5.66bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 60,627 characters.

The following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and the notes included in Part I, Item 1 *Financial Statements.*

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

### Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger combines Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business. The cash consideration for Energy Harbor Merger was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility, the Receivables Facility and the Repurchase Facility. See Note 2 to the Financial Statements for more information concerning the Energy Harbor Merger.

### 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 recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC provides a federal tax credit of up to $15/MWh, subject to phase out as power prices increase above $25/MWh, to existing nuclear facilities from 2024 through 2032. Treasury regulations are expected to further define the scope of the legislation in many important respects over the next twelve months, including critical guidance interpreting the nuclear PTC. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within IAS 20, as U.S. GAAP does not address how to account for these tax credits. We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with 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.

### Repurchase of TRA Rights and Preferred Stock Issuance

On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH, whereby we issued TRA rights to these former first-lien creditors of TCEH entitled to receive them under the Plan of Reorganization (TRA Rights). The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (i) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (ii) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.

Vistra began a series of repurchases of TRA Rights (Repurchase) from certain registered holders of the TRA Rights (Selling Holders) in December 2023. In connection with the Repurchase, holders of approximately 74% of the outstanding TRA Rights consented to certain amendments to the TRA which were effected in an Amended and Restated Tax Receivables Agreement (A&R TRA), dated as of December 29, 2023. Such amendments to the TRA included (i) the removal of the Company's obligation to provide registered holders of the TRA Rights (Holders) with regular reporting and access to information, (ii) limitations on the transferability of the TRA Rights, (iii) removal of certain obligations of the Company in the event it incurs indebtedness and (iv) a change to the definition of "Change of Control."

During December 2023, we repurchased approximately 317 million TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $476 million. The consideration for the December 31, 2023 Repurchase was conveyed through the issuance of 476,081 shares of Vistra Series C Preferred Stock to the Selling Holders.

On January 11, 2024, we Repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $65 million using cash on hand.

On January 31, 2024, we announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business of February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase. On the Early Tender Date the Company Repurchased TRA Rights in exchange for total consideration of $83 million and on February 28, 2024 additional TRA Rights were repurchased under the cash tender offer for total consideration of $3 million or $1.45 per TRA Right accepted for purchase.

As of March 31, 2024, we have repurchased an aggregate 98% of the initial issuance of TRA Rights upon Emergence, of which 8,195,063 TRA Rights remain outstanding. See Note 13 to the Financial Statements for details of the TRA and Note 16 to the Financial Statements for details of the Series C Preferred Stock.

### Macroeconomic Conditions

Historically, the base case assumption for U.S. electricity demand was for modest growth driven by the interplay of growth in population, industrial activity and new demand sources (like electric vehicles), partially offset by continued advancements in energy efficiency. Multiple demand drivers such as emergence of large load data centers and electrification of oil field operations (specifically the Permian Basin of west Texas), have accelerated load growth in the geographic regions we serve. We continue to monitor the impact of load growth on electricity demand and our operations.

The industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased (i) the lead time to procure certain materials necessary to maintain, and (ii) the labor costs associated with maintenance activity on 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 continues to drive elevated interest rates, resulting in increased refinancing or borrowing costs, including recently completed and expected future non-recourse financing for our development projects, recently completed corporate debt refinancing activities, and refinancing expected in connection with debt due in 2025 and beyond.

We are closely monitoring developments in the Russia and Ukraine conflict, specifically with regards to, (i) sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and (ii) actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. On April 30, 2024, the Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress and is expected to be submitted to and signed by President Biden. The PRUI Act would become effective 90 days after the President's signature. If the PRUI Act becomes effective, it would prohibit importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, the PRUI Act would release $2.72 billion in federal funding to ramp up production of domestic uranium fuel. We are monitoring the status of the PRUI Act and evaluating the potential impacts of the PRUI Act on our operations. Our 2024 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel. We are taking affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility through potential Russian supply disruption. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance, and therefore, we have enough nuclear fuel contracted to support all our refueling needs, including the Energy Harbor facilities acquired, through 2027.

### 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. Except as discussed below, the Company's critical accounting policies are disclosed in our 2023 Form 10-K.

### Business Combinations

Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 2 to the Financial Statements. The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant and equipment and asset retirement obligations:

#### Property, Plant and Equipment

The fair value of each power plant acquired was estimated using a combination of an income approach and a market approach. The income approach is based on the discounted cash flow method that uses (i) our estimates of forecasted future growth and long term prices of electricity, capacity and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses, and taxes, as well as working capital and capital asset requirements. Projected cash flows are then discounted to a present value employing a discount rate that properly accounts for the estimated market weighted-average cost of capital, as well as any risks unique to the subject cash flows. These estimates are subjective in nature and require judgement to interpret market data. The market valuation method used prices paid for a reasonably similar asset by other purchasers in the relevant market, with adjustments relating to physical differences in the asset as well as their locations.

#### Nuclear Decommissioning Asset Retirement Obligation

To estimate our nuclear decommissioning asset retirement obligation on assets acquired from Energy Harbor, we used a discounted cash flow model based on our estimates of cost escalation factors and discount rates, and considered multiple decommissioning scenarios: (i) DECON, which assumes major decommissioning activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently decontaminated within 60 years after the facility ceases operations. The probability-weighted estimated future cash flows were discounted using our specific credit-adjusted, risk-free rates which reflected the secured nature of the obligation due to acquired investments in NDTs which are intended to fund the future decommissioning obligations.

### RESULTS OF OPERATIONS

Net income decreased $680 million to Net income of $18 million for the three months ended March 31, 2024 compared to the three months ended March 31, 2023. For additional information see the following discussion of our results of operations.

### EBITDA and Adjusted EBITDA

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 (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. 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.

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 condensed consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

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).

### Vistra Consolidated Financial Results — Three Months Ended March 31, 2024 Compared to the Three Months Ended March 31, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2024:

*(in millions)*

|  | Three Months Ended March 31, 2024 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $2,494 | $439 | $637 | $285 | $239 | $— | $(1,040) | $3,054 |
| Fuel, purchased power costs and delivery fees | (1,647) | (368) | (526) | (80) | (134) | (1) | 1,040 | (1,716) |
| Operating costs | (31) | (248) | (124) | (16) | (66) | (12) | (1) | (498) |
| Depreciation and amortization | (23) | (132) | (192) | (21) | (20) | — | (15) | (403) |
| Selling, general and administrative expenses | (225) | (34) | (18) | (5) | (11) | (9) | (49) | (351) |
| Operating income (loss) | 568 | (343) | (223) | 163 | 8 | (22) | (65) | 86 |
| Other income | — | 3 | 39 | 1 | — | 3 | 45 | 91 |
| Other deductions | (1) | (1) | — | — | (1) | (1) | — | (4) |
| Interest expense and related charges | (6) | 10 | (1) | — | — | (1) | (172) | (170) |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | — | (5) | (5) |
| Income (loss) before income taxes | 561 | (331) | (185) | 164 | 7 | (21) | (197) | (2) |
| Income tax benefit | — | — | — | — | — | — | 20 | 20 |
| **Net income (loss)** | $561 | $(331) | $(185) | $164 | $7 | $(21) | $(177) | $18 |
| Income tax benefit | — | — | — | — | — | — | (20) | (20) |
| Interest expense and related charges (a) | 6 | (10) | 1 | — | — | 1 | 172 | 170 |
| Depreciation and amortization (b) | 23 | 158 | 215 | 21 | 20 | — | 16 | 453 |
| **EBITDA before Adjustments** | 590 | (183) | 31 | 185 | 27 | (20) | (9) | 621 |
| Unrealized net (gain) loss resulting from commodity hedging transactions | (623) | 584 | 193 | (129) | 155 | (4) | — | 176 |
| Purchase accounting impacts | (2) | — | (2) | — | — | — | (14) | (18) |
| Impacts of Tax Receivable Agreement (c) | — | — | — | — | — | — | (5) | (5) |
| Non-cash compensation expenses | — | — | — | — | — | — | 21 | 21 |
| Transition and merger expenses | 1 | — | 4 | — | — | — | 28 | 33 |
| Decommissioning-related activities (d) | — | 5 | (26) | — | 2 | — | — | (19) |
| ERP system implementation | — | — | — | — | — | — | 6 | 6 |
| Other, net | 6 | 5 | 1 | 3 | — | 1 | (41) | (25) |
| **Adjusted EBITDA** | $(28) | $411 | $201 | $59 | $184 | $(23) | $(14) | $790 |

(a) Includes $47 million of unrealized mark-to-market net gains on interest rate swaps.

(b) Includes nuclear fuel amortization of $26 million and $23 million, respectively, in Texas and East segments.

(c) Includes $10 million gain recognized on the repurchase of TRA Rights in the three months ended March 31, 2024 (see Note 13 to the Financial Statements).

(d) Represents net of all NDT income (loss), ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2023:

*(in millions)*

|  | Three Months Ended March 31, 2023 Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $2,350 | $1,353 | $1,809 | $231 | $828 | $— | $(2,146) | $4,425 |
| Fuel, purchased power costs and delivery fees | (2,690) | (395) | (820) | (148) | (262) | (1) | 2,146 | (2,170) |
| Operating costs | (28) | (228) | (65) | (15) | (65) | (20) | — | (421) |
| Depreciation and amortization | (29) | (130) | (161) | (15) | (14) | — | (17) | (366) |
| Selling, general and administrative expenses | (191) | (31) | (19) | (6) | (13) | (8) | (20) | (288) |
| Impairment of long-lived assets | — | — | — | — | (49) | — | — | (49) |
| Operating income (loss) | (588) | 569 | 744 | 47 | 425 | (29) | (37) | 1,131 |
| Other income | — | 12 | 1 | 1 | 1 | 3 | 2 | 20 |
| Other deductions | — | (1) | — | — | (1) | — | (1) | (3) |
| Interest expense and related charges | (7) | 4 | — | 4 | (1) | (1) | (206) | (207) |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | — | (65) | (65) |
| Income (loss) before income taxes | (595) | 584 | 745 | 52 | 424 | (27) | (307) | 876 |
| Income tax expense | — | — | — | — | — | — | (178) | (178) |
| **Net income (loss)** | $(595) | $584 | $745 | $52 | $424 | $(27) | $(485) | $698 |
| Income tax expense | — | — | — | — | — | — | 178 | 178 |
| Interest expense and related charges (a) | 7 | (4) | — | (4) | 1 | 1 | 206 | 207 |
| Depreciation and amortization (b) | 29 | 153 | 161 | 15 | 14 | — | 17 | 389 |
| **EBITDA before Adjustments** | (559) | 733 | 906 | 63 | 439 | (26) | (84) | 1,472 |
| Unrealized net (gain) loss resulting from commodity hedging transactions | 559 | (346) | (923) | (18) | (340) | (17) | — | (1,085) |
| Generation plant retirement expenses | — | — | — | — | — | — | 1 | 1 |
| Fresh start/purchase accounting impacts | 1 | (1) | 2 | — | 1 | — | — | 3 |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | — | 65 | 65 |
| Non-cash compensation expenses | — | — | — | — | — | — | 22 | 22 |
| Transition and merger expenses | (2) | — | — | — | 1 | — | 2 | 1 |
| Impairment of long-lived assets | — | — | — | — | 49 | — | — | 49 |
| PJM capacity performance default impacts (c) | — | — | 14 | — | 6 | — | — | 20 |
| Winter Storm Uri impacts (d) | (34) | 1 | — | — | — | — | — | (33) |
| Other, net | 6 | (4) | 2 | 1 | 8 | 2 | (17) | (2) |
| **Adjusted EBITDA** | $(29) | $383 | $1 | $46 | $164 | $(41) | $(11) | $513 |

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

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

GAAP operating income decreased $1.045 billion to operating income of $86 million in the three months ended March 31, 2024 compared to the three months ended March 31, 2023. The primary driver for the decrease is a $1.261 billion change in unrealized mark-to-market activity as results for the three months ended March 31, 2024 were unfavorably impacted by $176 million in pre-tax unrealized mark-to-market losses on derivative positions due to power and natural gas forward market curves moving up in the three months ended March 31, 2024 compared to $1.085 billion in pre-tax unrealized mark-to-market gains on commodity derivative positions due to power and natural gas forward market curves moving down in the three months ended March 31, 2023. See further information on our derivative results in *Energy-Related Commodity Contracts and Mark-to-Market Activities* below.

In addition to the mark-to-market impacts discussed above, operating results for the three months ended March 31, 2024, compared to the three months ended March 31, 2023 were impacted by additional factors including:

Favorable impacts:

- Expiration of contracts in the East segment which resulted in higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices in the three months ended March 31, 2023.
- Addition of Energy Harbor in March 2024 with results reflected in the East and Retail segments.

Unfavorable impacts:

- Decreases in capacity revenues primarily in the Sunset segment.
- Increase in selling, general and administrative expenses in Retail and Corp driven primarily by the addition of Energy Harbor.

The following table presents operational performance of our retail and generation segments:

| Retail sales volumes (GWh): Retail electricity sales volumes: | Three Months Ended March 31, Retail 2024 | 2023 | Texas 2024 | 2023 | East 2024 | 2023 | West 2024 | 2023 | Sunset 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Sales volumes in ERCOT | 16,074 | 14,982 |  |  |  |  |  |  |  |  |
| Sales volumes in Northeast/Midwest | 10,261 | 5,830 |  |  |  |  |  |  |  |  |
| Total retail electricity sales volumes | 26,335 | 20,812 |  |  |  |  |  |  |  |  |
| **Production volumes (GWh):** |  |  |  |  |  |  |  |  |  |  |
| Natural gas facilities |  |  | 8,151 | 6,225 | 14,762 | 14,585 | 1,228 | 1,543 |  |  |
| Lignite and coal facilities |  |  | 4,797 | 4,971 |  |  |  |  | 3,551 | 3,516 |
| Nuclear facilities |  |  | 5,008 | 5,227 | 2,329 |  |  |  |  |  |
| Solar facilities |  |  | 156 | 154 |  |  |  |  |  |  |
| **Capacity factors:** |  |  |  |  |  |  |  |  |  |  |
| CCGT facilities |  |  | 43.8% | 35.0% | 61.5% | 62.2% | 55.0% | 70.1% |  |  |
| Lignite and coal facilities |  |  | 57.1% | 59.7% |  |  |  |  | 35.5% | 35.6% |
| Nuclear facilities |  |  | 95.6% | 100.9% | 77.4% |  |  |  |  |  |
| **Weather - percent of normal (a):** |  |  |  |  |  |  |  |  |  |  |
| Heating degree days | 90% | 83% | 93% | 81% | 87% | 84% | 117% | 149% | 88% | 87% |

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

| Market pricing | Three Months Ended March 31, 2024 |  | 2023 | Average Market On-Peak Power Prices ($MWh) (b): | Three Months Ended March 31, 2024 | 2023 |
| --- | ---: | --- | ---: | --- | ---: | ---: |
| Average ERCOT North power price ($/MWh) | $21.66 |  | $21.98 | PJM West Hub | $36.03 | $36.35 |
|  |  | AEP Dayton Hub | $33.11 | $33.65 |  |  |
| Average NYMEX Henry Hub natural gas price ($/MMBtu) | $2.43 |  | $2.68 | NYISO Zone C | $38.13 | $30.96 |
|  |  | Massachusetts Hub | $47.97 | $51.98 |  |  |
| **Average natural gas price (a):** |  |  |  | Indiana Hub | $36.79 | $35.52 |
| TetcoM3 ($/MMBtu) | $2.90 |  | $2.93 | Northern Illinois Hub | $30.34 | $29.58 |
| Algonquin Citygates ($/MMBtu) | $4.26 |  | $5.13 | CAISO NP15 | $50.86 | $100.31 |

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

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

For the three months ended March 31, 2024, other income totaled $91 million driven by NDT net gains of $35 million, interest income of $23 million and a gain of $10 million on TRA repurchases. For the three months ended March 31, 2023, other income totaled $20 million driven by interest income.

Consolidated interest expense and related charges decreased $37 million in the three months ended March 31, 2024 compared to the three months ended March 31, 2023 primarily due to unrealized mark-to-market gains on interest rate swaps of $47 million in 2024 compared to unrealized mark-to-market losses on interest rate swaps of $41 million in 2023 due to an increase in interest rates in the three months ended March 31, 2024 compared to a decrease in the three months ended March 31, 2023, partially offset by an increase in interest paid/accrued of $52 million driven by higher average borrowings and rates in 2024. See Note 18 to the Financial Statements.

The following table presents additional changes to Net income (loss) and Adjusted EBITDA for the three months ended March 31, 2024 compared to the three months ended March 31, 2023.

*(in millions)*

|  | Three Months Ended March 31, 2024 Compared to 2023 Retail (a) | Texas | East (a) | West | Sunset |
| --- | ---: | ---: | ---: | ---: | ---: |
| Favorable change in realized revenue net of fuel driven by effectiveness of hedging strategies (b), rolloff of negative margin default service contracts in East and addition of Energy Harbor | $— | $46 | $246 | $11 | $17 |
| Higher margins driven by addition of Energy Harbor | 8 |  |  |  |  |
| Favorable impact of less Winter Storm Uri bill credits applied | 27 | — | — | — | — |
| Negative impacts of milder weather in 2024 | (4) |  |  |  |  |
| Increase in operating costs due primarily to change in generation volumes | — | (15) | (47) | (1) | 1 |
| Change in SG&A and other | (30) | (3) | 1 | 3 | 2 |
| **Change in Adjusted EBITDA** | **$1** | **$28** | **$200** | **$13** | **$20** |
| Favorable/(unfavorable) change in depreciation and amortization | 6 | (5) | (54) | (6) | (6) |
| Change in unrealized net gains (losses) on hedging activities (b) | 1,182 | (930) | (1,116) | 111 | (495) |
| Impairment of long-lived assets | — | — | — | — | 49 |
| Decommissioning related activities | — | (5) | 26 | — | (2) |
| PJM capacity performance default impacts | — | — | 14 | — | 6 |
| Winter Storm Uri impact | (34) | 1 | — | — | — |
| Other (including interest expenses) | 1 | (4) | — | (6) | 11 |
| **Change in Net income (loss)** | **$1,156** | **$(915)** | **$(930)** | **$112** | **$(417)** |

(a) Includes amounts associated with March 2024 operations acquired in the Energy Harbor Merger.

(b) See *Energy-Related Commodity Contracts and Mark-to-Market Activities* below for analysis of hedging strategy.

**Asset Closure Segment — Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023**

*(in millions)*

|  | Three Months Ended March 31, 2024 | 2023 | Favorable (Unfavorable) Change |
| --- | ---: | ---: | ---: |
| Fuel, purchased power costs and delivery fees | $(1) | $(1) | $— |
| Operating costs | (12) | (20) | 8 |
| Selling, general and administrative expenses | (9) | (8) | (1) |
| Operating loss | (22) | (29) | 7 |
| Other income | 3 | 3 | — |
| Other deductions | (1) | — | (1) |
| Interest expense and related charges | (1) | (1) | — |
| Loss before income taxes | (21) | (27) | 6 |
| **Net loss** | **$(21)** | **$(27)** | **$6** |
| **Adjusted EBITDA** | **$(23)** | **$(41)** | **$18** |

Operating costs for the three months ended March 31, 2024 and 2023 include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. GAAP and Adjusted EBITDA results for 2024 are favorable compared to 2023 primarily due to higher costs incurred in 2023 for the January 2023 retirement of the Edwards generation facility.

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

As forward power prices materially increased in 2022, our generation segments (Texas, East, West and Sunset) aggressively sold forward power for future years. We entered the 2023 and 2024 calendar years with more than 99% of our expected generation volumes hedged. While settled power prices in the first quarter of 2023 and 2024 are lower than historical averages, the strategic hedging allowed us to lock in margins above what we would have been able to realize if unhedged. Additionally, the margins we were able to lock in with hedges for the first quarter of 2024 were higher than the first quarter of 2023 which is driving the increase in realized revenue net of fuel in the generation segments along with the addition of Energy Harbor in the East segment. The forward power sales are also the drivers of the changes in unrealized gains/losses on hedging activities. As power prices increase/decrease in comparison to what our generation segments have sold forward, the generation segments recognize unrealized losses/gains. The retail segment procures power from the generation segments to serve future load obligations and thus changes in forward power prices have an inverse effect on unrealized mark to market for the retail segment as compared to the generation segments. This is evident in the first quarter of 2023 as decrease in forward power prices drove material unrealized gains in our generation segment, partially offset by unrealized losses in our retail segment. In the first quarter of 2024, forward power prices increased slightly which resulted in unrealized losses in our generation segments which is partially offset by unrealized gains in our retail segment.

The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2024 and 2023. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $176 million in unrealized net losses and $1.085 billion in unrealized net gains for the three months ended March 31, 2024 and 2023, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

*(in millions)*

|  | Three Months Ended March 31, 2024 | 2023 |
| --- | ---: | ---: |
| Commodity contract net liability at beginning of period | $(2,740) | $(3,148) |
| Settlements/termination of positions (a) | 387 | 711 |
| Changes in fair value of positions in the portfolio (b) | (563) | 374 |
| Acquired commodity contracts (c) | (39) | — |
| Other activity (d) | 47 | (36) |
| Commodity contract net liability at end of period | $(2,908) | $(2,099) |

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(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) Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements).

(d) Primarily 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.

The following maturity table presents the net commodity contract liability arising from recognition of fair values as of March 31, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

*(in millions)*

| Source of Fair Value | Maturity dates of unrealized commodity contract net liability as of March 31, 2024 Less than 1 year | 1-3 years | 4-5 years | Excess of 5 years | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Prices actively quoted | $(521) | $(272) | $1 | $— | $(792) |
| Prices provided by other external sources | (578) | (389) | — | — | (967) |
| Prices based on models | (322) | (609) | (130) | (88) | (1,149) |
| Total | $(1,421) | $(1,270) | $(129) | $(88) | $(2,908) |

60

We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of March 31, 2024 were as follows:

| Nuclear/Renewable/Coal Generation: | Balance of 2024 | 2025 |
| --- | ---: | ---: |
| Texas | 100% | 100% |
| East | 74% | 39% |
| Sunset | 97% | 66% |
| Natural Gas Generation: |  |  |
| Texas | 95% | 84% |
| East | 100% | 84% |
| West | 100% | 99% |

61

### Financial Condition

### Cash Flows

#### Operating Cash Flows

Cash provided by operating activities totaled $312 million and $1.435 billion in the three months ended March 31, 2024 and 2023, respectively. The unfavorable change of $1.123 billion was primarily driven by a lower decrease in net margin deposits (returns of cash related to commodity contracts which support our hedging strategy) as $128 million was returned in the three months ended March 31, 2024 as compared to $1.227 billion returned in the three months ended March 31, 2023, partially offset by cash received from an increase in realized energy margins recognized in the three months ended March 31, 2024 compared to the three months ended March 31, 2023.

*Depreciation and amortization —* 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 $152 million and $111 million for the three months ended March 31, 2024 and 2023, 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 (see Note 7 to the Financial Statements).

#### Investing Cash Flows

Cash used in investing activities totaled $3.528 billion and $513 million for the three months ended March 31, 2024 and 2023, respectively. The increase of $3.015 billion was driven primarily by (a) $3.1 billion used to fund the Energy Harbor Merger and (b) $88 million in higher net purchases of environmental allowances, partially offset by a $125 million increase in proceeds from sales of property, plant and equipment, including nuclear fuel.

*(in millions)*

|  | Three Months Ended March 31, 2024 | 2023 | Increase (Decrease) |
| --- | ---: | ---: | ---: |
| Capital expenditures, including LTSA prepayments | $(152) | $(202) | $50 |
| Nuclear fuel purchases | (220) | (64) | (156) |
| Growth and development expenditures | (93) | (218) | 125 |
| Total capital expenditures | (465) | (484) | 19 |
| Energy Harbor acquisition (net of cash acquired) | (3,070) | — | (3,070) |
| Net sales (purchases) of environmental allowances | (114) | (26) | (88) |
| Proceeds from sales of property, plant and equipment, including nuclear fuel | 127 | 2 | 125 |
| Other investing activity | (6) | (5) | (1) |
| Cash used in investing activities | $(3,528) | $(513) | $(3,015) |

62

#### Financing Cash Flows

Cash provided by financing activities totaled $793 million in the three months ended March 31, 2024 compared to cash used in financing activities of $874 million in the three months ended March 31, 2023. The change of $1.667 billion was driven by (a) the net borrowing of $1.375 billion of short-term debt and accounts receivable financing amounts in the three months ended March 31, 2024 to partially fund the Energy Harbor Merger compared to the net repayment of $475 million of short-term debt and accounts receivable financing amounts in the three months ended March 31, 2023 and (b) $700 million of borrowings under the Vistra Zero Term Loan B Facility, partially offset by cash used for long-term debt and TRA tender offers executed in January 2024.

*(in millions)*

|  | Three Months Ended March 31, 2024 | 2023 | Increase (Decrease) |
| --- | ---: | ---: | ---: |
| Share repurchases | $(291) | $(301) | $10 |
| Issuances of long-term debt | 700 | — | 700 |
| Other net long-term borrowings (repayments) | (756) | (7) | (749) |
| Net short-term borrowings (repayments) | 500 | (650) | 1,150 |
| Net borrowings (repayments) under the accounts receivable financing facilities | 875 | 175 | 700 |
| Dividends paid to common stockholders | (77) | (77) | — |
| TRA Repurchase and tender offer — return of capital | (122) | — | (122) |
| Other financing activity | (36) | (14) | (22) |
| Cash used in financing activities | $793 | $(874) | $1,667 |

### 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.

In May 2024 and July 2024, after taking into account the Senior Secured Notes Tender Offer settled in January 2024, $342 million of 4.875% Senior Secured Notes and $1.155 billion of 3.550% Senior Secured Notes, respectively, will reach maturity. We plan to fund these upcoming principal payments using a combination of (a) the proceeds from the issuance of $500 million of 6.000% Senior Secured Notes due 2034 and $1.0 billion of 6.875% Senior Unsecured Notes due 2032 and (b) cash on hand. Increases in interest rates have resulted in, and will likely continue to result in, increased borrowing costs.

See Note 8 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

### Available Liquidity

The following table summarizes changes in available liquidity for the three months ended March 31, 2024:

*(in millions)*

|  | March 31, 2024 | December 31, 2023 | Change |
| --- | ---: | ---: | ---: |
| Cash and cash equivalents (a) | $1,070 | $3,485 | $(2,415) |
| Vistra Operations Credit Facilities — Revolving Credit Facility (b) | 1,293 | 1,213 | 80 |
| Vistra Operations — Commodity-Linked Facility (c) | 637 | 1,101 | (464) |
| Total available liquidity (d)(e) | $3,000 | $5,799 | $(2,799) |

(a) See the condensed consolidated statements of cash flows in the Financial Statements and *Cash Flows* above for details of the decrease in cash and cash equivalents for the three months ended March 31, 2024. The decrease includes $3.1 billion that was used to fund the Energy Harbor Merger.

(b) The increase in availability for the three months ended March 31, 2024 was driven by an $80 million decrease in letters of credit outstanding under the facility.

(c) As of both March 31, 2024 and December 31, 2023, the borrowing bases are less than the facility limit of $1.575 billion. As of March 31, 2024, available capacity reflects the borrowing base of $1.137 billion and $500 million in cash borrowings. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings.

(d) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 8 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, the Alternative LOC Facility or the Energy Harbor LOC Facility. See Note 10 to the Financial Statements for detail on our letter of credit facilities.

We believe that we will have access to sufficient liquidity to fund our other 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.

Including obligations assumed in the Energy Harbor Merger, our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $3.0 billion in fiscal year 2024, $2.9 billion in 2025-2026, $1.1 billion in 2027-2028 and $500 million thereafter.

### Capital Expenditures

Estimated 2024 capital expenditures and nuclear fuel purchases as of May 8, 2024 total approximately $1.943 billion and include:

- $822 million for investments in generation and mining facilities;
- $745 million for solar and energy storage development;
- $302 million for nuclear fuel purchases; and
- $74 million for other growth expenditures.

### Share Repurchase Program

In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date. In August 2022, March 2023 and February 2024, the Board authorized incremental amounts of $1.25 billion, $1.0 billion and $1.5 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $5.75 billion.

The following table provides information about our repurchases of common stock for the period between January 1, 2024 and May 3, 2024:

*(in millions, except share amounts and price paid per share)*

|  | $5.75 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, 2024 (a) | 6,138,773 | $46.21 | $284 |  |
| April 1, 2024 through May 3, 2024 | 1,455,357 | 71.34 | 104 |  |
| January 1, 2024 through May 3, 2024 | 7,594,130 | $51.02 | $388 | $1,862 |

(a) Shares repurchased include 72,839 of unsettled shares for $5 million as of March 31, 2024.

### Dividends

### Common Stock Dividends

In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations. Quarterly dividends paid per share of common stock in 2024 and 2023 are reflected in the table below.

| Three Months Ended March 31, 2024 Board Declaration Date | Payment Date | Per Share Amount | Year Ended December 31, 2023 Board Declaration Date | Payment Date | Per Share Amount |
| --- | --- | ---: | --- | --- | ---: |
| February 2024 | March 2024 | $0.2150 | February 2023 | March 2023 | $0.1975 |
|  |  |  | May 2023 | June 2023 | $0.2040 |
|  |  |  | July 2023 | September 2023 | $0.2060 |
|  |  |  | October 2023 | December 2023 | $0.2130 |

In May 2024, the Board declared a quarterly dividend of $0.2175 per share of common stock that will be paid in June 2024.

### Preferred Stock Dividends

Semiannual dividends paid per share of each respective preferred stock series in 2024 and 2023 are reflected in the table below. Dividends payable are recorded on the Board declaration date.

| Series A Preferred Stock Board Declaration Date | Payment Date | Per Share Amount | Series B Preferred Stock Board Declaration Date | Payment Date | Per Share Amount |
| --- | --- | ---: | --- | --- | ---: |
| February 2023 | April 2023 | $40.00 | May 2023 | June 2023 | $35.00 |
| August 2023 | October 2023 | $40.00 | November 2023 | December 2023 | $35.00 |
| February 2024 | April 2024 | $40.00 |  |  |  |

In May 2024, the Board declared a semi-annual dividend of $35.00 per share of Series B Preferred Stock that will be paid in June 2024 and an initial dividend of $48.32 per share on Series C Preferred Stock that will be paid in July 2024.

### 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 9 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities, the Commodity-Linked Facility, the Secured LOC Facilities, the Alternative LOC Facility and the Energy Harbor LOC 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 March 31, 2024, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

- $1.629 billion in cash and Eligible Assets have been posted with counterparties as compared to $1.244 billion posted as of December 31, 2023;
- $115 million in cash has been received from counterparties as compared to $45 million received as of December 31, 2023;
- $2.634 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of December 31, 2023; and
- $140 million in letters of credit have been received from counterparties as compared to $143 million received as of December 31, 2023.

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 expect to make approximately $4 million in federal income tax payments and $52 million in state income tax payments, offset by $8 million in state tax refunds.

For the three months ended March 31, 2024, there were no federal income tax payments, $3 million in state income tax payments, $1 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 March 31, 2024, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

See Note 10 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

### Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of March 31, 2024, Vistra has posted letters of credit in the amount of $95 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 $583 million in the form of letters of credit, $81 million in the form of a surety bond and $12 million of cash as of March 31, 2024 (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 $2.494 billion and $500 million, respectively, as of March 31, 2024.

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, Energy Harbor LLC, TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and 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 Operations, and 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 Alternative LOC Facility, 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 Alternative LOC Facility. 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 exceeding the threshold above, may result in a termination of the Alternative LOC Facility.

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.

A default by Vistra Zero or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $100 million and 75% of Consolidated EBITDA may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $700 million as of March 31, 2024.

### Guarantees

See Note 15 to the Financial Statements for discussion of guarantees.

### Commitments and Contingencies

See Note 15 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, 11,986 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 valuation, 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 these methods 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 certain VaR measures 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.

*(in millions)*

|  | Three Months Ended March 31, 2024 | Year Ended December 31, 2023 |
| --- | ---: | ---: |
| Month-end average VaR | $251 | $190 |
| Month-end high VaR | $329 | $423 |
| Month-end low VaR | $197 | $115 |

The month-end VaR risk measures in 2024 are consistent with prior year.

### Price Sensitivities

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 natural 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 natural gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of March 31, 2024.

*(in millions)*

| Texas: | Balance of 2024 | 2025 |
| --- | ---: | ---: |
| Natural Gas Generation: $1.00/MWh increase in spark spread | $3 | $8 |
| Natural Gas Generation: $1.00/MWh decrease in spark spread | $(2) | $(8) |
| Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price | $— | $9 |
| Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price | $(5) | $(15) |
| East: |  |  |
| Nuclear Generation: $2.50/MWh increase in power price | $17 | $50 |
| Nuclear Generation: $2.50/MWh decrease in power price | $(17) | $(50) |
| Natural Gas Generation: $1.00/MWh increase in spark spread | $1 | $10 |
| Natural Gas Generation: $1.00/MWh decrease in spark spread | $— | $(8) |
| Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price | $(6) | $(24) |
| Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price | $— | $20 |
| West: |  |  |
| 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) | $(2) |
| Sunset: |  |  |
| Coal Generation: $2.50/MWh increase in power price | $2 | $23 |
| Coal Generation: $2.50/MWh decrease in power price | $1 | $(23) |
| 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) |

### Interest Rate Risk

We manage our interest rate risk to limit the impact of interest rate changes on our results of operations and cash flows and to lower our overall borrowing costs. To achieve these objectives, a majority of our borrowings have fixed interest rates.

As of March 31, 2024, 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 $9 million taking into account the interest rate swaps discussed in Note 11 to Financial Statements. The inflationary environment continues to drive elevated interest rates, resulting in increased recently completed and expected refinancing or borrowing costs. See Item 2. *Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions.*

### 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 11 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 $2.164 billion as of March 31, 2024.

As of March 31, 2024, Retail segment credit exposure totaled approximately $1.392 billion, including $1.370 billion of trade accounts receivable and $22 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled $51 million, resulting in a net exposure of $1.341 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 March 31, 2024, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled $772 million including $681 million related to derivative assets and $91 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 exposure was $581 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of March 31, 2024. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.

*(in millions)*

|  | Exposure Before Credit Collateral | Credit Collateral | Net Exposure |
| --- | ---: | ---: | ---: |
| Investment grade | $633 | $111 | $522 |
| Below investment grade or no rating | 139 | 80 | 59 |
| Totals | $772 | $191 | $581 |

Significant (*i.e.*, 10% or greater) concentration of credit exposure exists with two counterparties, which represent an aggregate $310 million, or 53%, of our total net exposure as of March 31, 2024. 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 counterparties. 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.

## 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, 7,718 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 2023 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.

***We may suffer material losses, costs and liabilities due to operation risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the nuclear generation facilities.***

We own and operate nuclear generation facilities in Texas, Ohio, and Pennsylvania. The ownership and operation of nuclear generation facilities involves certain risks. These risks include:

- unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity, insider threat, third-party compromise or other problems;
- inadequacy or lapses in maintenance protocols;
- the impairment of reactor operation and safety systems due to human error or force majeure;
- the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;
- the costs of procuring nuclear fuel, including impacts from restrictions on imports from Russia or China (see Part I, Item 2. *Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions);*
- the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
- terrorist or cybersecurity attacks by nation-states or other threat actors and the cost to protect and recover against any such attack;
- the impact of a natural disaster;
- financial risk associated with retrospective insurance premium that could become due under secondary coverage required by the Price Anderson Act;
- limitations on the amounts and types of insurance coverage commercially available; and
- uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives.

Our financial performance could be materially and negatively affected by matters arising from our ownership and operation of nuclear facilities, including any prolonged unavailability of any of our nuclear generation facilities. The following are among the more significant related risks:

- *Operational Risk —* Operations at any generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur at a nuclear generation facility, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at our nuclear generation facilities.
- *Regulatory Risk —* The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, as to which no assurance can be given, the NRC operating licenses for the two units at the Comanche Peak Facility will expire in 2030 and 2033, respectively, and for the unit at the Perry Facility will expire in 2026, and are pending license renewal applications subject to review by the NRC. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
- *Spent Nuclear Fuel Storage.* Our nuclear operations produce various types of nuclear waste materials, including spent nuclear fuel. The availability of a national repository for the storage of spent nuclear fuel and the timing of that facility opening will significantly affect the costs associated with storage of spent nuclear fuel and the ultimate amounts received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of a repository for spent nuclear fuel could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether a fee may be established or to what extent in the future for spent nuclear fuel disposal.
- *Decommissioning Obligation and Funding*. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.

Actual costs to decommission our nuclear facilities may substantially exceed our estimates as a result of changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in federal or state regulatory requirements, other changes in our estimates or ability to effectively execute on our planned decommissioning activities.

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. In addition, financial market performance directly affects the asset values in the NDT trust funds. If the investments held by our PJM NDT funds are not sufficient to fund the decommissioning of our nuclear units, we could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.

- *Nuclear Accident Risk —* Although the safety record of our nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred at nuclear stations both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities that may exceed our resources, including insurance coverages, and could damage our reputation. Such liabilities to third parties are currently covered by a primary layer of financial protection required by the Price Anderson Act in the form of insurance carried by the owners of each nuclear facility and by a secondary layer of insurance coverage into which each nuclear licensee in the country is required to contribute in the event of an accident at any facility which exceeds the primary level of coverage for that facility. Our potential exposure for the secondary layer of coverage is currently capped at $165.9 million per reactor but is subject to adjustment for inflation, and the total retrospective premium per reactor per incident is capped at $24.7 million in any one year. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the impacted facility. Such accidents could also result in property damage to our nuclear plant and equipment, which could exceed coverage available under insurance provided by Nuclear Electric Insurance Limited. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected.

Filed May 10, 2024.
Source: SEC EDGAR, the filing index for accession 0001692819-24-000033. Last ingested by Listed: Nov 10, 2026, 02:46 ET. No prices; not investment advice.