# Vistra Corp.: Form 10-Q for the period ended Mar 31, 2025

- Company: [Vistra Corp.](/companies/vst.md) (CIK 1692819)
- Form: 10-Q
- Filed: 2025-05-08
- Accepted by EDGAR: May 7, 2025, 20:27 ET
- Period: 2025-03-31
- Accession: 0001692819-25-000035
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1692819/000169281925000035/vistra-20250331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1692819/000169281925000035/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $4.25bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Selling, general and administrative | 3 months, 2025-01-01 to 2025-03-31 | $391.0m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | −$120.0m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-01-01 to 2025-03-31 | $319.0m | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2025-01-01 to 2025-03-31 | −$176.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | −$268.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-01-01 to 2025-03-31 | −$0.93 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-01-01 to 2025-03-31 | −$0.93 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-01-01 to 2025-03-31 | 339,799,989 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $599.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2025-01-01 to 2025-03-31 | $768.0m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 3 months, 2025-01-01 to 2025-03-31 | $83.0m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 3 months, 2025-01-01 to 2025-03-31 | $337.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2025-03-31 | $561.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-03-31 | $8.43bn | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $38.23bn | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $9.75bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $33.39bn | us-gaap:Liabilities |
| Long-term debt | at 2025-03-31 | $16.30bn | us-gaap:LongTermDebt |
| Short-term borrowings | at 2025-03-31 | $1.35bn | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2025-03-31 | $4.83bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 52,961 characters.

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

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

### Macroeconomic Conditions

Our industry is subject to uncertainties associated with the impact of rapidly evolving technology on U.S. electricity demand, as well as evolving political, regulatory and economic uncertainties.

#### Electricity Demand

Emerging electricity demand drivers including the rise of large-scale data centers, the electrification of oil field operations, and electric vehicle load building are contributing to a faster-paced load growth in the regions we serve. Our integrated retail electricity and power generation operations allows us to quickly respond to electricity demand changes. We are actively engaged in discussions with various counterparties regarding the potential long-term sale of power from our nuclear and gas facilities to support large-scale electricity consumers.

Our business and these types of transactions are subject to inherent risks and uncertainties, including regulatory reviews, necessary approvals, and potential legislative actions. Such factors could affect the timing and feasibility of finalizing any definitive agreements with large scale electricity consumers.

#### Supply Chain Constraints

Our industry continues to face ongoing supply chain constraints and labor shortages, which have reduced the availability of essential equipment and supplies for constructing new generation facilities, increased lead times for procuring materials and raised labor costs associated with maintaining our natural gas, nuclear, and coal fleet.

We are proactively managing these constraints by continuously re-evaluating the business cases and timing of our planned development projects. This has led to the deferral of some planned capital expenditures for our renewables projects and could impact the economic feasibility of additional projects. We are engaging with suppliers to secure key materials needed to maintain our existing generation facilities before future planned outages.

#### Russia/Ukraine Conflict

We are closely monitoring developments in the Russia and Ukraine conflict, specifically sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. The Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress, signed into law by President Biden, and took effect on August 11, 2024. The PRUI Act prohibits importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until December 31, 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, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. On November 15, 2024, the Russian Federation temporarily suspended shipments of uranium to the U.S., stating that they would grant future export licenses on a case-by-case basis.

Our 2025 and 2026 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refueling schedules. All nuclear fuel requirements for 2025 and 2026 are either in inventory or are onshore. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance. We have nuclear fuel contracted to support all our refueling needs through 2030 without any additional Russian deliveries. We continue to take 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 facilities through potential Russian supply disruption.

### Moss Landing 300 Incident

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site (the Moss Landing Incident) that resulted in ceasing operations at all facilities at the Moss Landing complex until the fire was contained. No injuries occurred due to the fire or the Company's response. The Moss Landing complex includes two other battery facilities and a gas plant. The gas plant returned to service in February, but the two battery facilities remain offline as we continue to investigate the cause of the fire. We expect the Moss Landing 350 MW battery to return to service at some point later this year. There is less certainty about the return to service regarding the Moss Landing 100 MW battery. We will know more after the investigation of the cause of the Moss Landing Incident is complete. As of March 31, 2025, the net book value of the Moss Landing 100 facility was approximately $170 million.

As a result of the damage caused by the Moss Landing Incident, during the three months ended March 31, 2025, we wrote-off the net book value of Moss Landing 300 of approximately $400 million to depreciation expense and moved the asset to the Asset Closure segment as we have no plans to return the Moss Landing 300 facility to operations (see Notes 6 and 16 to the Financial Statements). We have recognized expense of approximately $7 million for costs incurred to respond to the Moss Landing Incident through March 31, 2025. As of March 31, 2025, we accrued approximately $70 million in obligations related to the Moss Landing Incident including approximately $30 million for anticipated air and soil monitoring requirements and $40 million for the expected costs of decommissioning the Moss Landing 300 structure, which includes demolition of the structure, removing and disposing of the batteries, and fulfilling land reclamation obligations (see Note 13 to the Financial Statements). Additional costs incurred from the Moss Landing Incident include loss of revenue from the facilities being offline and may include litigation costs and penalties under contracts. We are currently unable to estimate the full impact the Moss Landing Incident will have on us as our estimate will evolve as demolition progresses.

We have filed insurance claims against applicable insurance policies with combined business interruption and property loss limits of $500 million, net of deductibles. As of March 31, 2025, the insurance receivable asset related to expenses we believe are probable of recovery from property damage insurance was $425 million recorded as offsets to the costs and expenses incurred in other noncurrent assets on the condensed consolidated balance sheet. Given uncertainty in timing of insurance recoveries and additional expenses that could be incurred related to the fire, we cannot predict the full impacts this event will have on our 2025 financial statements.

### Martin Lake Unit 1 Incident

On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT, an 815 MW unit. We wrote-off the net book value of Unit 1 of the Martin Lake facility of less than $1 million to depreciation expense in December 2024. We currently expect the unit to return to service in late 2025. We incurred approximately $30 million in cash capital expenditures during the three-months ended March 31, 2025 to restore the unit to service. Cash capital expenditures to return the unit to service in 2025 are expected to be approximately $270 million. We expect to recover a majority of the expenditures associated with the Martin Lake Unit 1 through property damage insurance and receive additional business interruption proceeds. However, given uncertainty in timing of insurance recoveries and asset restart date, we cannot predict the net impacts these events will have on our 2025 financial statements.

### Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (as amended, the UPAs) with each of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue), pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for approximately $3.2 billion in cash (collectively, the Transaction). The Transaction closed on December 31, 2024 and Vistra Vision Holdings now owns 100% of the equity interests in Vistra Vision. See Notes 2 and 9 to the Financial Statements for additional information.

### Planned Gas-Fueled Dispatchable Power in ERCOT

In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity in west, central, and north Texas consisting of the following projects:

- Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry.
- Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.
- Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.

Our announced plan is based on market reforms that policymakers passed in the 2023 Texas legislative session, which ERCOT and the PUCT are currently implementing. These market reforms are focused on grid reliability and proper market signals. If successfully implemented, they could offer the regulatory framework necessary for Vistra to confidently make the long-term investments in these capacity projects. In addition, in July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above. Both projects were selected for due diligence as part of the Texas Energy Fund loan program, which is ongoing. An invitation to due diligence does not mean an applicant is awarded a loan. Vistra's decision to move forward with the new west Texas gas plant projects are contingent upon supportive market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation.

### 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 and 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 combined 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 additional information.

### Nuclear Plant License Renewal

In 2023, the Perry Nuclear Plant filed a license extension application to operate through 2046, an additional 20 years beyond the existing license. A decision from the NRC is expected in late 2025.

### Inflation Reduction Act of 2022 (IRA)

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, and a first-time stand-alone battery storage investment tax credit. The IRA also implements 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 is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh (each subject to annual inflation adjustments). The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, *Accounting for Government Grants and Disclosures of Government Assistance*. As discussed in Note 1 to the Financial Statements in our 2024 Form 10-K, we recognized transferable nuclear PTC revenues of $545 million in the year ended December 31, 2024. U.S. Treasury regulations are expected to further define the scope of the legislation in many important respects, including critical guidance interpreting the nuclear PTC. This guidance could have a material impact on our estimate and would be reflected as a change in estimate in the period in which the guidance is received. We do not expect Vistra to be subject to the CAMT in the 2025 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.

### 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 in the condensed consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2024 Form 10-K.

### Results of Operations

Net income (loss) decreased $286 million to a Net loss of $268 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. 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 the 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).

49

### Vistra Consolidated Financial Results — Three Months Ended March 31, 2025 Compared to the Three Months Ended March 31, 2024

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2025:

*(in millions)*

|  | Three Months Ended March 31, 2025 Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $3,168 | $210 | $1,380 | $157 | $4 | $(986) | $3,933 |
| Fuel, purchased power costs, and delivery fees | (1,712) | (497) | (1,172) | (52) | — | 986 | (2,447) |
| Operating costs | (40) | (258) | (327) | (12) | (56) | — | (693) |
| Depreciation and amortization | (23) | (150) | (316) | (15) | 1 | (19) | (522) |
| Selling, general, and administrative expenses | (243) | (41) | (58) | (2) | (17) | (30) | (391) |
| Operating income (loss) | 1,150 | (736) | (493) | 76 | (68) | (49) | (120) |
| Other income (deductions) | — | 2 | (9) | — | 1 | 1 | (5) |
| Interest expense and related charges | (18) | 14 | 12 | 1 | (1) | (327) | (319) |
| Income (loss) before income taxes | 1,132 | (720) | (490) | 77 | (68) | (375) | (444) |
| Income tax benefit | — | — | — | — | — | 176 | 176 |
| **Net income (loss)** | $1,132 | $(720) | $(490) | $77 | $(68) | $(199) | $(268) |
| Income tax benefit | — | — | — | — | — | (176) | (176) |
| Interest expense and related charges (a) | 18 | (14) | (12) | (1) | 1 | 327 | 319 |
| Depreciation and amortization (b) | 23 | 181 | 396 | 15 | (1) | 19 | 633 |
| **EBITDA before Adjustments** | 1,173 | (553) | (106) | 91 | (68) | (29) | 508 |
| Unrealized net (gain) loss resulting from commodity hedging transactions | (997) | 1,030 | 567 | (32) | (1) | — | 567 |
| Purchase accounting impacts | — | — | 14 | — | — | — | 14 |
| Non-cash compensation expenses | — | — | — | — | — | 21 | 21 |
| Transition and merger expenses | — | — | 1 | — | — | 17 | 18 |
| Decommissioning-related activities (c) | — | 5 | 35 | — | 46 | — | 86 |
| Other, net | 8 | 8 | 3 | 3 | (1) | (19) | 2 |
| **Adjusted EBITDA** | $184 | $490 | $514 | $62 | $(24) | $(10) | $1,216 |

(a) Includes $48 million of unrealized mark-to-market net losses on interest rate swaps.

(b) Includes nuclear fuel amortization of $31 million and $80 million, respectively, in the Texas and East segments.

(c) Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses.

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 | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $2,494 | $459 | $856 | $276 | $9 | $(1,040) | $3,054 |
| Fuel, purchased power costs, and delivery fees | (1,647) | (381) | (647) | (79) | (2) | 1,040 | (1,716) |
| Operating costs | (31) | (257) | (181) | (11) | (17) | (1) | (498) |
| Depreciation and amortization | (23) | (134) | (210) | (14) | (7) | (15) | (403) |
| Selling, general, and administrative expenses | (225) | (35) | (28) | (4) | (10) | (49) | (351) |
| Operating income (loss) | 568 | (348) | (210) | 168 | (27) | (65) | 86 |
| Other income (deductions) | (1) | 2 | 38 | — | 3 | 45 | 87 |
| Interest expense and related charges | (6) | 10 | (1) | — | (1) | (172) | (170) |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | (5) | (5) |
| Income (loss) before income taxes | 561 | (336) | (173) | 168 | (25) | (197) | (2) |
| Income tax benefit | — | — | — | — | — | 20 | 20 |
| **Net income (loss)** | $561 | $(336) | $(173) | $168 | $(25) | $(177) | $18 |
| Income tax benefit | — | — | — | — | — | (20) | (20) |
| Interest expense and related charges (a) | 6 | (10) | 1 | — | 1 | 172 | 170 |
| Depreciation and amortization (b) | 23 | 160 | 233 | 14 | 7 | 16 | 453 |
| **EBITDA before Adjustments** | 590 | (186) | 61 | 182 | (17) | (9) | 621 |
| Unrealized net (gain) loss resulting from commodity hedging transactions | (623) | 604 | 328 | (129) | (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) | — | 6 | (25) | — | — | — | (19) |
| ERP system implementation | — | — | — | — | — | 6 | 6 |
| Other, net | 6 | 5 | 1 | 3 | 1 | (41) | (25) |
| **Adjusted EBITDA** | $(28) | $429 | $367 | $56 | $(20) | $(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 the Texas and East segments.

(c) Includes $10 million gain recognized on the repurchase of TRA Rights.

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

GAAP net income (loss) decreased $286 million to a net loss of $268 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. The primary drivers for the decrease in GAAP net income (loss) include:

Unfavorable impacts:

- An increase of $391 million in unrealized mark-to-market losses on derivative positions due to power and natural gas curves moving up more significantly in the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. See further information on our derivative results in *Energy-Related Commodity Contracts and Mark-to-Market Activities* below.

Favorable impacts:

- Inclusion of three months of Energy Harbor activity in the East and Retail segments for 2025 compared to one month in 2024.

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

| Retail electricity sales volumes (GWh): | Three Months Ended March 31, Retail 2025 | 2024 | Texas 2025 | 2024 | East 2025 | 2024 | West 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Sales volumes in ERCOT | 17,965 | 16,074 |  |  |  |  |  |  |
| Sales volumes in Northeast/Midwest | 15,358 | 10,261 |  |  |  |  |  |  |
| Total retail electricity sales volumes | 33,323 | 26,335 |  |  |  |  |  |  |
| **Production volumes (GWh):** |  |  |  |  |  |  |  |  |
| Natural gas facilities |  |  | 9,145 | 8,151 | 14,642 | 14,762 | 502 | 1,228 |
| Lignite and coal facilities |  |  | 5,437 | 5,114 | 5,174 | 3,234 |  |  |
| Nuclear facilities |  |  | 5,229 | 5,008 | 7,679 | 2,329 |  |  |
| Solar facilities |  |  | 162 | 156 | 44 |  |  |  |
| **Capacity factors:** |  |  |  |  |  |  |  |  |
| CCGT facilities |  |  | 48.1% | 43.8% | 63.2% | 61.5% | 22.7% | 55.0% |
| Lignite and coal facilities |  |  | 56.0% | 52.1% | 61.0% | 37.7% |  |  |
| Nuclear facilities |  |  | 100.9% | 95.6% | 87.9% | 77.4% |  |  |
| **Weather - percent of normal (a):** |  |  |  |  |  |  |  |  |
| Heating degree days | 105% | 90% | 113% | 93% | 101% | 87% | 124% | 117% |

(a) Reflects cooling degree or heating degree days based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Retail amounts represent weather data for the Dallas Forth Worth area.

| Average Power Price ($MWh) (a): | Three Months Ended March 31, 2025 | 2024 | Average Natural Gas Price ($MWh) (b): | Three Months Ended March 31, 2025 | 2024 |
| --- | ---: | ---: | --- | ---: | ---: |
| ERCOT North Hub | $30.91 | $21.58 | NYMEX Henry Hub | $4.28 | $2.43 |
| ERCOT West Hub | $30.13 | $25.70 | Houston Ship Channel | $3.46 | $1.92 |
| PJM AEP Dayton Hub | $47.91 | $29.57 | Permian Basin | $1.83 | $1.21 |
| PJM Northern Illinois Hub | $35.19 | $25.97 | Dominion South | $3.74 | $1.86 |
| PJM Western Hub | $53.91 | $32.61 | Tetco ELA | $4.06 | $2.27 |
| MISO Indiana Hub | $44.84 | $32.65 | Chicago Citygate | $4.00 | $2.85 |
| ISONE Massachusetts Hub | $102.77 | $43.93 | Tetco M3 | $6.42 | $2.90 |
| New York Zone A | $68.63 | $32.67 | Algonquin Citygates | $11.83 | $4.26 |
| CAISO NP15 | $40.89 | $50.46 | PG&E Citygate | $3.71 | $3.90 |

(a) Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized.

(b) Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.

Adjusted EBITDA for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 increased by $426 million. The primary drivers for the increase include:

*(in millions)*

|  | Three Months Ended March 31, 2025 Compared to 2024 Retail (a) | Texas | East (a) | West |
| --- | ---: | ---: | ---: | ---: |
| Favorable change in realized revenue net of fuel driven primarily by addition of Energy Harbor in East. | $— | $65 | $293 | $6 |
| Higher retail margins driven by favorable power supply costs, customer count growth, and inclusion of a full quarter of Energy Harbor retail contracts | 213 | — | — | — |
| Favorable impact of higher average consumption primarily due to weather | 19 | — | — | — |
| Increase in plant operating costs due primarily to addition of Energy Harbor in East | — | 5 | (134) | (1) |
| Change in SG&A and other primarily due to increase in costs related to addition of Energy Harbor in Retail and East | (20) | (9) | (12) | 1 |
| **Change in Adjusted EBITDA** | **$212** | **$61** | **$147** | **$6** |
| Change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East | — | (21) | (163) | (1) |
| Change in unrealized net gains (losses) on hedging activities (b) | 374 | (426) | (239) | (97) |
| Decommissioning related activities | — | 1 | (60) | — |
| Other (including interest expenses) | (15) | 1 | (2) | 1 |
| **Change in Net income (loss)** | **$571** | **$(384)** | **$(317)** | **$(91)** |

(a) Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.

(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, 2025 Compared to Three Months Ended March 31, 2024**

*(in millions)*

|  | Three Months Ended March 31, 2025 | 2024 | Favorable (Unfavorable) Change |
| --- | ---: | ---: | ---: |
| Operating revenues | $4 | $9 | $(5) |
| Fuel, purchased power costs, and delivery fees | — | (2) | 2 |
| Operating costs | (56) | (17) | (39) |
| Depreciation and amortization | 1 | (7) | 8 |
| Selling, general, and administrative expenses | (17) | (10) | (7) |
| Operating loss | (68) | (27) | (41) |
| Other income (deductions) | 1 | 3 | (2) |
| Interest expense and related charges | (1) | (1) | — |
| Loss before income taxes | (68) | (25) | (43) |
| **Net loss** | **$(68)** | **$(25)** | **$(43)** |
| **Adjusted EBITDA** | **$(24)** | **$(20)** | **$(4)** |

GAAP results for the three months ended March 31, 2025 are unfavorable compared to the three months ended March 31, 2024 primarily due to operating costs associated with the Moss Landing 300 Incident net of insurance receivables. See Note 1 to the Financial Statements for additional information.

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

As we entered the 2024 and 2025 calendar years, we had substantially all of our expected generation volumes hedged. This strategic hedging allowed us to lock in margins that were higher than what we would have realized if we had not hedged. These margins also exceeded those from hedging activities for the three months ended March 31, 2024, contributing to the increase in realized revenue net of fuel in our generation segments, along with the addition of Energy Harbor.

The changes in unrealized gains and losses on hedging activities are driven by forward power sales. When power prices increase or decrease compared to what our generation segments have sold forward, the generation segments recognize unrealized losses or gains, respectively. Conversely, the retail segment, which procures power from the generation segments to meet future load obligations, experiences an inverse effect on unrealized mark-to-market valuations compared to the generation segments.

In the first quarters of both 2024 and 2025, forward power prices in our Texas and East generation segments increased relative to our hedged positions resulting in unrealized losses in those segments, which were 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, 2025 and 2024.

*(in millions)*

|  | Three Months Ended March 31, 2025 | 2024 |
| --- | ---: | ---: |
| Commodity contract net liability as of January 1 | $(1,459) | $(2,740) |
| Mark-to-market adjustments: |  |  |
| Settlements/termination of positions (a) | 189 | 387 |
| Changes in fair value of positions in the portfolio (b) | (756) | (563) |
| Net loss associated with mark-to-market accounting | (567) | (176) |
| Acquired commodity contracts (c) | — | (39) |
| Other activity (d) | 5 | 47 |
| Commodity contract net liability as of March 31 | $(2,021) | $(2,908) |

(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, 2025, 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, 2025 Less than 1 year | 1-3 years | 4-5 years | Excess of 5 years Total |
| --- | ---: | ---: | ---: | ---: |
| Prices actively quoted | $(284) | $(56) | $21 | $$ (319) |
| Prices provided by other external sources | $(643) | $(116) | $1 | $$ (758) |
| Prices based on models | $(360) | $(578) | $(34) | $28 $(944) |
| Total | $(1,287) | $(750) | $(12) | $28 $(2,021) |

54

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, and West segments as of March 31, 2025 were as follows:

| Nuclear/Renewable/Coal Generation: | Balance of 2025 | 2026 |
| --- | ---: | ---: |
| Texas | 100% | 100% |
| East | 97% | 65% |
| Natural Gas Generation: |  |  |
| Texas | 100% | 65% |
| East | 100% | 100% |
| West | 100% | 39% |

### Financial Condition

### Cash Flows

#### Operating Cash Flows

Cash provided by operating activities totaled $599 million and $312 million for the three months ended March 31, 2025 and 2024, respectively. The favorable change of $287 million was primarily driven by a full quarter of Energy Harbor activity in 2025 and higher realized revenues net of fuel costs as compared to 2024. These favorable changes are partially offset by a $345 million decrease in net cash flows related to margin deposits as $217 million in net margin deposits related to commodity contracts supporting our hedging strategy were posted for the three months ended March 31, 2025 as compared to $128 million in net margin deposits returned for the three months ended March 31, 2024.

#### Investing Cash Flows

Cash used in investing activities includes:

*(in millions)*

|  | Three Months Ended March 31, 2025 | 2024 | Increase (Decrease) |
| --- | ---: | ---: | ---: |
| Capital expenditures, including LTSA prepayments | $(265) | $(152) | $(113) |
| Nuclear fuel purchases | (242) | (220) | (22) |
| Growth and development expenditures | (261) | (93) | (168) |
| Total capital expenditures | (768) | (465) | (303) |
| Energy Harbor acquisition (net of cash acquired) | — | (3,070) | 3,070 |
| Net sales (purchases) of environmental allowances | (286) | (114) | (172) |
| Proceeds from sales of property, plant, and equipment, including nuclear fuel | — | 127 | (127) |
| Other investing activity | (7) | (6) | (1) |
| Cash used in investing activities | $(1,061) | $(3,528) | $2,467 |

The change of $2.467 billion was primarily driven by $3.1 billion used to fund the Energy Harbor Merger in 2024 and partially offset by higher capital expenditures and net purchases of environmental allowances in 2025 primarily driven by the addition of Energy Harbor.

#### Financing Cash Flows

Cash (used in) provided by financing activities includes:

*(in millions)*

|  | Three Months Ended March 31, 2025 | 2024 | Increase (Decrease) |
| --- | ---: | ---: | ---: |
| Share repurchases | $(337) | $(291) | $(46) |
| Issuances of long-term debt | — | 700 | (700) |
| Other net long-term borrowings (repayments) | (6) | (756) | 750 |
| Net short-term borrowings (repayments) | — | 500 | (500) |
| Net borrowings (repayments) under the accounts receivable financing facilities | 332 | 875 | (543) |
| Dividends paid to common stockholders | (83) | (77) | (6) |
| Dividends paid to preferred stockholders | (21) | — | (21) |
| Tax withholding on stock based compensation | (50) | (12) | (38) |
| TRA Repurchase and tender offer — return of capital | — | (122) | 122 |
| Other financing activity | 1 | (24) | 25 |
| Cash (used in) provided by financing activities | $(164) | $793 | $(957) |

The change of $957 million was primarily driven by the net borrowing of $332 million of short-term debt and accounts receivable financing in the three months ended March 31, 2025 compared to the net borrowing of $1.375 billion in the three months ended March 31, 2024 reflecting amounts borrowed to partially fund the Energy Harbor Merger.

### Available Liquidity

The following table summarizes changes in available liquidity for the three months ended March 31, 2025:

*(in millions)*

|  | March 31, 2025 | December 31, 2024 | Change |
| --- | ---: | ---: | ---: |
| Cash and cash equivalents (a) | $561 | $1,188 | $(627) |
| Vistra Operations Credit Facilities — Revolving Credit Facility (b) | 2,217 | 2,162 | 55 |
| Vistra Operations — Commodity-Linked Facility (c) | 1,125 | 771 | 354 |
| Total available liquidity (d)(e) | $3,903 | $4,121 | $(218) |

(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, 2025.

(b) The increase in availability for the three months ended March 31, 2025 was driven by a $55 million decrease in letters of credit outstanding under the facility.

(c) As of March 31, 2025 and December 31, 2024, the borrowing bases were less than the facility limit of $1.75 billion. As of March 31, 2025, available capacity reflects the borrowing base of $1.125 billion and no cash borrowings. As of December 31, 2024, available capacity reflects the borrowing base of $771 million and no cash borrowings.

(d) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for additional information.

(e) Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC Facilities. See Note 9 to the Financial Statements for additional information.

We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months, including the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra Vision and maturity of the Vistra Operations Senior Secured Notes due May 2025 discussed in Note 9 to the Financial Statements. 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 8 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 9 to the Financial Statements for additional information.

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, 2025, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

- $1.025 billion in cash and Eligible Assets has been posted with counterparties as compared to $841 million posted as of December 31, 2024;
- $5 million in cash has been received from counterparties as compared to $49 million received as of December 31, 2024;
- $2.439 billion in letters of credit has been posted with counterparties as compared to $2.560 billion posted as of December 31, 2024; and
- $89 million in letters of credit has been received from counterparties as compared to $131 million received as of December 31, 2024.

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 $23 million in federal income tax payments, $85 million in state income tax payments, and $2 million in TRA payments, offset by $14 million in state tax refunds.

For the three months ended March 31, 2025, there were no federal income tax payments, $5 million in state income tax payments, no 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 revolving letters of credit outstanding (excluding all undrawn revolving letters of credit and cash collateralized backstopped revolving letters of credit) exceed 35% of the revolving commitments), 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). Although the period ended March 31, 2025 was not a compliance period, we would have been in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement, and Secured LOC Facilities financial covenants if they were required to be tested at such time. See Note 9 to the Financial Statements for additional information.

### 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, 2025, Vistra has posted letters of credit in the amount of $86 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 $843 million in the form of letters of credit, $81 million in the form of a surety bond and $3 million of cash as of March 31, 2025 (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 greatest of $1.0 billion, 17.5% of Consolidated EBITDA, and 2.5% of Consolidated Total Assets 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 $2.469 billion and zero, respectively, as of March 31, 2025.

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 Receivables 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 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 the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Alternative 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 exceeding the threshold above, may result in a termination of the Alternative LOC Facilities.

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes, the 6.000% Senior Secured Notes, the 5.050% Senior Secured Notes, and the 5.700% 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 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 Operating or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $100 million, 75% of Consolidated EBITDA, and 6% of Consolidated Total Assets may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility, which totaled approximately $697 million as of March 31, 2025.

A default by BCOP or any of its subsidiary guarantors in respect of certain provisions defined in the applicable agreement may result in a cross default under the BCOP Credit Agreement. Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility. In addition, the interest rate swap agreements that are secured with a lien on BCOP and its subsidiary guarantors' assets on a pari passu basis with the BCOP Credit Agreement contain cross-acceleration provisions, where an event of a default by BCOP or any of its subsidiary guarantors 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 BCOP and require all outstanding obligations under such agreement to be settled.

Under the Nuveen UPA, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary 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 UPA. Such a default would result in the payment obligations under the Nuveen UPA of Vistra Vision Holdings and/or any guarantor thereunder becoming immediately due and payable.

### Guarantees

See Note 13 to the Financial Statements for additional information.

### Commitments and Contingencies

See Note 13 to the Financial Statements for additional information.

### Changes in Accounting Standards

See Note 1 to the Financial Statements for additional information.

## Market risk

As filed, 8,600 characters.

In the normal course of business, our financial position is routinely subject to a variety of risks, including market risks associated with (i) changes in commodity prices, (ii) interest rate movements on outstanding debt, and (iii) credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due to us.

Market risks are monitored by our risk management group which operates independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These practices and methodologies measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions. Measurement techniques include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Risk management regularly reports their analysis to the Company's Risk Committee and Executive Committee, and to the Sustainability and Risk Committee of the Board of Directors.

### Commodity Price Risk and Oversight

Our business is subject to the inherent risks of market fluctuations in the price of commodities for energy-related products we market or purchase in futures markets including electricity, natural gas, uranium, coal, environmental credits and other energy commodities in competitive wholesale markets. Factors that influence these market fluctuations are dependent upon many factors outside of our control including seasonal changes in supply and demand, weather conditions, market liquidity, governmental, regulatory, and environmental policies.

We manage the commodity price 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. In managing commodity 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. 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. Our nuclear fleet is eligible for the nuclear PTC provided by the IRA, which provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program.

### 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. This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts. 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 following table summarizes the VaR for Vistra's commodity portfolio based on a 95% confidence level and an assumed holding period of 60 days. Average VaRs are the average of each month-end average for the three months ended March 31, 2025 and the year ended December 31, 2024, respectively.

*(in millions)*

|  | Three Months Ended March 31, 2025 | Year Ended December 31, 2024 |
| --- | ---: | ---: |
| Average VaR | $292 | $236 |
| High VaR | $316 | $371 |
| Low VaR | $250 | $86 |

### Interest Rate Risk

We are exposed to fluctuations in interest rates through our issuance of variable rate debt. We mitigate our exposure to fluctuations in interest rates through entering interest rate swaps. These interest rate swaps limit the impact of interest rate changes on our results of operations and cash flows and lower our overall borrowing costs. Interest rate risk is managed centrally by our treasury function.

As of March 31, 2025, we have approximately $3.5 billion principal amount of variable rate debt consisting of the Vistra Operations Credit Facilities Term Loan B-3 Facility, the BCOP Credit Facilities and the Vistra Zero Term Loan B Facility (see Note 9 to the Financial Statements). We have entered into net notional interest rate swaps that will hedge $2.3 billion of our exposure to Vistra Operations variable rate debt through December 2030 and $108 million of our project-level debt through March 2045 (see Note 10 to Financial Statements). As of March 31, 2025, 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 $12 million after taking into account the interest rate swaps.

### Credit Risk

Our primary concentration of credit risk is associated with the collection of receivables resulting from sales to retail customers and the risk of a counterparty's failure to meet its obligations under derivative contracts. We minimize our exposure to credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial conditions, 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 10 to the Financial Statements for additional information.

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 $2.249 billion as of March 31, 2025. Including collateral posted to us by counterparties, our net exposure was $2.140 billion, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of March 31, 2025. 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 Trade Accounts Receivable | Derivatives | Gross Exposure | Credit Collateral | Net Exposure |
| --- | ---: | ---: | ---: | ---: | ---: |
| Retail segment | $1,543 | $(11) | $1,532 | $53 | $1,479 |
| Texas, East, and Asset Closure segments: |  |  |  |  |  |
| Investment grade | $89 | $393 | $482 | $17 | $465 |
| Below investment grade or no rating | 13 | 222 | 235 | 39 | 196 |
| Texas, East, and Asset Closure segments | $102 | $615 | $717 | $56 | $661 |
| Totals | $1,645 | $604 | $2,249 | $109 | $2,140 |

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.

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. Significant (*i.e.*, 10% or greater) concentration of credit exposure exists with two counterparties, which represented an aggregate $431 million, or 65%, of our total net exposure of our wholesale segments as of March 31, 2025. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, market role and deemed creditworthiness and the importance of our business relationship with the counterparties.

## Controls and procedures

As filed, 1,113 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), along with 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, 325 characters.

As of the date of this Quarterly Report on Form 10-Q, there have been no material changes to the risk factors discussed in Part I, Item 1A *Risk Factors* in our 2024 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.

Filed May 8, 2025.
Source: SEC EDGAR, the filing index for accession 0001692819-25-000035. Last ingested by Listed: Nov 6, 2026, 11:32 ET. No prices; not investment advice.