What changed in this filing

/stocks — the workspaceLOADING

Item 8. Financial Statements and Supplementary Data

2022-02-25 compared with 2021-02-26 · 564 added, 754 removed, 1794 unchanged (42% of the section changed)

42 unchanged sentences

Critical Audit Matter Description

The Company has assets and liabilities whose fair values are based on complex proprietary models and unobservable inputs.

The Company has assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs.

These financial instruments can span a broad array of product types and generally include (1) electricity purchases and sales that include power and heat rate positions;

(2) forward purchase contracts of congestion revenue rights and financial transmission rights;

(2) physical electricity options, spread options, swaptions, and natural gas options;

and (4) contracts for natural gas and coal.

(3) forward purchase contracts of congestion revenue rights and financial transmission rights;

and (4) contracts for natural gas, coal, and environmental allowances.

Under accounting principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3 derivative assets or liabilities.

4 unchanged sentences

• We tested the effectiveness of controls over derivative asset and liability valuations, including controls related to price verification of illiquid price curves.

• We assessed to determine if management had consistently applied significant unobservable valuation assumptions.

• We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2020, to confirm our understanding of the types of instruments outstanding and performed a sensitivity analysis to understand the most significant assumptions impacting fair value.

• We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2021, to confirm our understanding of the types of instruments outstanding.

• We assessed the consistency by which management has applied significant unobservable valuation assumptions.

• With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair value of a sample of Level 3 derivative instruments and compared our estimates to the Company's estimates.

Impairment of Long-Lived Assets —Refer to Notes 1 and 21 to the financial statements

Critical Audit Matter Description

The Company evaluates the carrying value of long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable.

Indicators of impairment may include declines in the forward prices of natural gas or electricity subsequent to the asset acquisition date, or an expectation that "more likely than not" a long-lived asset will be sold or otherwise disposed of significantly before the end of its estimated useful life.

Management determines if long-lived assets are impaired by comparing the forecasted undiscounted future cash flows to the carrying value.

The forecasted undiscounted future cash flows include significant unobservable inputs such as forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures and forecasted delivered fuel prices.

The carrying value of such assets is not recoverable if the forecasted undiscounted future cash flows are less than the carrying value.

If the long-lived assets are not recoverable, fair value will be calculated based on a market participant view and a loss will be recorded based on the amount by which the carrying value exceeds the fair value.

In determining the fair value of the long-lived assets, management uses a combination of a market approach valuation based on transactions of similar assets and an income approach valuation discounting the forecasted future cash flows.

In 2020, management evaluated several of its power generation facilities for recoverability.

Management concluded that three of the power generation facilities evaluated were not recoverable.

The Company recorded impairment losses related to the three facilities of $324 million in 2020.

As of December 31, 2020, the total carrying value of long-lived property, plant and equipment assets that are subject to evaluation for indicators of impairment was approximately $13.5 billion.

Given (1) management's evaluation of the recoverability of long-lived assets required management to make significant estimates and assumptions related to the development of forecasted undiscounted future cash flows, and (2) for those long-lived assets deemed impaired, the determination of fair value required management to make significant estimates and assumptions related to the discount rates to apply to the forecasted future cash flows, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists and fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the evaluation of management’s estimate of the forecasted future cash flows utilized in the evaluation of recoverability and determination of fair value of the long-lived assets deemed to be impaired included the following, among others:

• We tested the effectiveness of controls over management’s development of the assumptions used to estimate the forecasted future cash flows for the long-lived assets.

• We evaluated the reasonableness of management’s forecasted generation plant performance and forecasted capital expenditures assumptions by comparing the estimates to:

◦ Historical generation volume output and capital expenditures for the respective long-lived assets

◦ Internal communications to management and the Board of Directors

• With the assistance of our energy commodity fair value specialists:

◦ We developed independent estimates of the forward natural gas and electricity prices and compared our estimates to the Company's estimates.

◦ We evaluated the reasonableness of the Company's forward capacity prices, including the key assumptions underlying the development of those prices.

• With the assistance of our fair value specialists:

◦ We developed a range of independent discount rates and compared those to the discount rates used by management in the income approach used to determine fair value of the impaired long-lived assets.

/s/ Deloitte & Touche LLP

11 unchanged sentences

Selling, general and administrative expenses ( 1,040 ) ( 1,035 ) ( 904 )

Impairment of long-lived assets ( 356 ) — —

Operating income 1,519 1,993 491

Impairment of long-lived and other assets ( 71 ) ( 356 ) —

Operating income (loss) ( 1,515 ) 1,519 1,993

Other income (Note 21) 140 34 56

6 unchanged sentences

Net income (loss) ( 1,264 ) 624 926

Net loss attributable to noncontrolling interest 12 2 2

Net (income) loss attributable to noncontrolling interest ( 10 ) 12 2

Net income (loss) attributable to Vistra $ ( 1,274 ) $ 636 $ 928

11 unchanged sentences

Net income (loss) $ ( 1,264 ) $ 624 $ 926

Other comprehensive loss, net of tax effects:

Effects related to pension and other retirement benefit obligations (net of tax benefit of $ 5 , $ 4 and $ 2 )

Other comprehensive income (loss), net of tax effects:

Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $ 9 , ($ 5 ) and ($ 4 ))

32 ( 18 ) ( 8 )

Adoption of new accounting standard — — 1

Total other comprehensive loss ( 18 ) ( 8 ) ( 5 )

Total other comprehensive income (loss) 32 ( 18 ) ( 8 )

Comprehensive income (loss) ( 1,232 ) 606 918

Comprehensive loss attributable to noncontrolling interest 12 2 2

Comprehensive income (loss) attributable to noncontrolling interest ( 10 ) 12 2

Comprehensive income (loss) attributable to Vistra $ ( 1,242 ) $ 618 $ 920

6 unchanged sentences

Net income (loss) $ ( 1,264 ) $ 624 $ 926

Adjustments to reconcile net income (loss) to cash provided by operating activities:

Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:

Depreciation and amortization 2,050 2,048 1,876

Deferred income tax expense (benefit), net ( 475 ) 230 281

Impairment of long-lived assets (Note 4) 356 — —

Loss on disposal of investment in NELP (Note 21) 29 — —

Impairment of long-lived and other assets 71 356 —

Loss on disposal of investment in NELP — 29 —

Unrealized net (gain) loss from mark-to-market valuations of commodities 759 ( 231 ) ( 696 )

Unrealized net loss from mark-to-market valuations of interest rate swaps 155 220 5

Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps ( 134 ) 155 220

Change in asset retirement obligation liability ( 5 ) 7 ( 48 )

Asset retirement obligation accretion expense 38 43 53

Impacts of Tax Receivable Agreement (Note 8) ( 5 ) 37 79

Impacts of Tax Receivable Agreement ( 53 ) ( 5 ) 37

Bad debt expense 110 110 82

7 unchanged sentences

Margin deposits, net ( 1,000 ) ( 20 ) 170

Uplift securitization proceeds receivable from ERCOT ( 544 ) — —

Accrued interest 13 ( 20 ) 80

1 unchanged sentence

Accrued employee incentive ( 68 ) 39 1

Tax Receivable Agreement payment (Note 8) — ( 2 ) ( 16 )

Tax Receivable Agreement payment ( 2 ) — ( 2 )

Asset retirement obligation settlement ( 88 ) ( 118 ) ( 121 )

2 unchanged sentences

Other — net liabilities 237 ( 91 ) 142

Cash provided by operating activities 3,337 2,736 1,471

Cash provided by (used in) operating activities ( 206 ) 3,337 2,736

Cash flows — investing activities:

Capital expenditures, including nuclear fuel purchases and LTSA prepayments ( 1,033 ) ( 1,259 ) ( 713 )

Ambit acquisition (net of cash acquired) (Note 2) — ( 506 ) —

Crius acquisition (net of cash acquired) (Note 2) — ( 374 ) —

Cash acquired in the Merger (Note 2) — — 445

Proceeds from sales of nuclear decommissioning trust fund securities (Note 21) 433 431 252

Investments in nuclear decommissioning trust fund securities (Note 21) ( 455 ) ( 453 ) ( 274 )

Ambit acquisition (net of cash acquired) — — ( 506 )

Crius acquisition (net of cash acquired) — — ( 374 )

Proceeds from sales of nuclear decommissioning trust fund securities 483 433 431

Investments in nuclear decommissioning trust fund securities ( 505 ) ( 455 ) ( 453 )

Proceeds from sales of environmental allowances 392 165 197

Purchases of environmental allowances ( 605 ) ( 504 ) ( 322 )

Proceeds from sales of assets 24 6 7

Insurance proceeds 89 35 23

Proceeds from sale of assets 30 24 6

CONSOLIDATED STATEMENTS OF CASH FLOWS

5 unchanged sentences

Cash flows — financing activities:

Issuances of long-term debt (Note 11) — 6,507 1,000

Repayments/repurchases of debt (Note 11) ( 1,008 ) ( 7,109 ) ( 3,075 )

Net borrowings/(payments) under accounts receivable securitization program (Note 10) ( 150 ) 111 339

Borrowings under Revolving Credit Facility (Note 11) 1,075 650 —

Repayments under Revolving Credit Facility (Note 11) ( 1,425 ) ( 300 ) —

Debt tender offer and other debt financing fees (Note 11) ( 17 ) ( 203 ) ( 236 )

Stock repurchase (Note 14) — ( 656 ) ( 763 )

Dividends paid to stockholders (Note 14) ( 266 ) ( 243 ) —

Issuances of preferred stock 2,000 — —

Issuances of long-term debt 1,250 — 6,507

Repayments/repurchases of debt ( 381 ) ( 1,008 ) ( 7,109 )

Borrowings under Term Loan A 1,250 — —

Repayment under Term Loan A ( 1,250 ) — —

Proceeds from forward capacity agreement 500 — —

Net borrowings/(payments) under accounts receivable financing ( 300 ) ( 150 ) 111

Borrowings under Revolving Credit Facility 1,450 1,075 650

Repayments under Revolving Credit Facility ( 1,450 ) ( 1,425 ) ( 300 )

Debt tender offer and other financing fees ( 13 ) ( 17 ) ( 203 )

Share repurchases ( 471 ) — ( 656 )

Dividends paid to stockholders ( 290 ) ( 266 ) ( 243 )

Other, net ( 21 ) ( 5 ) 6

Cash used in financing activities ( 1,796 ) ( 1,237 ) ( 2,723 )

Cash provided by (used in) financing activities 2,274 ( 1,796 ) ( 1,237 )

Net change in cash, cash equivalents and restricted cash 915 ( 31 ) ( 218 )

8 unchanged sentences

Trade accounts receivable — net (Note 21) 1,397 1,279

Income taxes receivable 15 —

Inventories (Note 21) 610 515

1 unchanged sentence

Margin deposits related to commodity contracts 1,263 257

Uplift securitization proceeds receivable from ERCOT (Note 1) 544 —

Prepaid expense and other current assets 195 205

2 unchanged sentences

Investments (Note 21) 2,049 1,759

Investment in unconsolidated subsidiary (Note 21) — 124

Operating lease right-of-use assets (Note 12) 40 45

8 unchanged sentences

Current liabilities:

Short-term borrowings (Note 11) $ — $ 350

Accounts receivable securitization program (Note 10) 300 450

Accounts receivable financing (Note 10) $ — $ 300

Long-term debt due currently (Note 11) 254 95

21 unchanged sentences

Total equity (Note 14):

Preferred stock, number of shares authorized — 100,000,000 ;

Series A (liquidation preference — $ 1,000 ;

shares outstanding:

December 31, 2021 — 1,000,000 ;

December 31, 2020 — zero );

Series B (liquidation preference — $ 1,000 ;

shares outstanding:

December 31, 2021 — 1,000,000 ;

December 31, 2020 — zero )

Common stock (par value — $ 0.01 ;

9 unchanged sentences

Retained deficit ( 1,964 ) ( 399 )

( 399 ) ( 764 )

Accumulated other comprehensive loss ( 16 ) ( 48 )

1 unchanged sentence

Noncontrolling interest in subsidiary 1 ( 10 )

Total equity 8,292 8,361

Total liabilities and equity $ 29,683 $ 25,208

2 unchanged sentences

(Millions of Dollars)

Common Stock Treasury Stock Additional Paid-In Capital Retained Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity

Balances at December 31, 2017 $ 4 $ — $ 7,765 $ ( 1,410 ) $ ( 17 ) $ 6,342 $ — $ 6,342

Stock and stock compensation awards issued in connection with the Merger 1 — 1,901 — — 1,902 — 1,902

Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Retained Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity

December 31, 2018 $ — $ 5 $ ( 778 ) $ 10,107 $ ( 1,449 ) $ ( 22 ) $ 7,863 $ 4 $ 7,867

Stock repurchases — — ( 641 ) — — — ( 641 ) — ( 641 )

Shares issued for tangible equity unit contracts — — 446 ( 446 ) — — — — —

Effects of stock-based compensation — — — 62 — — 62 — 62

Tangible equity units acquired — — 369 — — 369 — 369

Warrants acquired — — 2 — — 2 — 2

Net loss — — — — 928 — 928 ( 2 ) 926

Dividends declared on common stock — — — — ( 243 ) — ( 243 ) — ( 243 )

Adoption of new accounting standards — — — — ( 2 ) — ( 2 ) — ( 2 )

Pension and OPEB liability — change in funded status — — — — — ( 8 ) ( 8 ) — ( 8 )

Investment by noncontrolling interest — — — — — — 6 6

Other — — — ( 2 ) 2 — — ( 1 ) ( 1 )

Balances at December 31, 2018 $ 5 $ ( 778 ) $ 10,107 $ ( 1,449 ) $ ( 22 ) $ 7,863 $ 4 $ 7,867

Stock repurchases — ( 641 ) — — — ( 641 ) — ( 641 )

Shares issued for tangible equity unit contracts — 446 ( 446 ) — — — — —

December 31, 2019 $ — $ 5 $ ( 973 ) $ 9,721 $ ( 764 ) $ ( 30 ) $ 7,959 $ 1 $ 7,960

Effects of stock-based compensation — — — 65 — — 65 — 65

3 unchanged sentences

Pension and OPEB liability — change in funded status — — — — — ( 18 ) ( 18 ) — ( 18 )

Investment by noncontrolling interest — — — — — — — 1 1

Other — — — — ( 1 ) — ( 1 ) — ( 1 )

Balances at December 31, 2019 $ 5 $ ( 973 ) $ 9,721 $ ( 764 ) $ ( 30 ) $ 7,959 $ 1 $ 7,960

December 31, 2020 $ — $ 5 $ ( 973 ) $ 9,786 $ ( 399 ) $ ( 48 ) $ 8,371 $ ( 10 ) $ 8,361

Stock repurchases ( 585 ) ( 585 ) ( 585 )

Series A Preferred Stock issued 1,000 — — ( 10 ) — — 990 — 990

Series B Preferred Stock issued 1,000 ( 15 ) 985 — 985

Effects of stock-based compensation — — — 60 — — 60 — 60

1 unchanged sentence

Dividends declared on common stock — — — — ( 290 ) — ( 290 ) — ( 290 )

Adoption of new accounting standard — — — ( 4 ) — ( 4 ) — ( 4 )

Pension and OPEB liability — change in funded status — — — — — 32 32 — 32

Investment by noncontrolling interest — — — — — — — 1 1

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Millions of Dollars)

Other — — — 3 ( 1 ) — 2 — 2

Balances at December 31, 2020 $ 5 $ ( 973 ) $ 9,786 $ ( 399 ) $ ( 48 ) $ 8,371 $ ( 10 ) $ 8,361

December 31, 2021 $ 2,000 $ 5 $ ( 1,558 ) $ 9,824 $ ( 1,964 ) $ ( 16 ) $ 8,291 $ 1 $ 8,292

See Notes to the Consolidated Financial Statements.

5 unchanged sentences

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S.

Through our subsidiaries, we are engaged in competitive energy market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Effective July 2, 2020, we changed our name from Vistra Energy Corp.

to Vistra Corp.

(Vistra) to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect or integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business powering the communities we serve with safe, reliable power.

(Vistra) to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect or integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business leading the clean power transition through our Vistra Zero portfolio while powering the communities we serve with safe, reliable and affordable power.

Vistra has six reportable segments:

(i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.

In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources.

Management believes that the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants.

The following is a summary of the updated segments:

• The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments.

As we announced significant plant closures in the third quarter of 2020, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.

• The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S.

electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes operations in PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.

• The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporate and Other non-segment.

As reflected by the Moss Landing and Oakland ESS projects (see Note 3), the Company expects to expand its operations in the West segment.

In addition, the ERCOT segment was renamed the Texas segment.

There were no changes to the Retail and Asset Closure segments.

All historical segment results within these consolidated financial statements have been recast to be in alignment with our new segmentation.

See Note 20 for further information concerning reportable business segments.

Ambit Transaction

On November 1, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of Ambit (Ambit Transaction).

Because the Ambit Transaction closed on November 1, 2019, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Ambit and its subsidiaries prior to November 1, 2019.

See Note 2 for a summary of the Ambit Transaction.

Crius Transaction

On July 15, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly owned the operating business of Crius (Crius Transaction).

Because the Crius Transaction closed on July 15, 2019, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Crius and its subsidiaries prior to July 15, 2019.

See Note 2 for a summary of the Crius Transaction.

Dynegy Merger Transaction

On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement.

Pursuant to the Merger Agreement, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation.

Because the Merger closed on April 9, 2018, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy prior to April 9, 2018.

See Note 2 for a summary of the Merger transaction and business combination accounting.

See Note 20 for further information concerning our reportable business segments, including an update of our reportable segments in the third quarter of 2020.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas.

This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021.

Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows.

The primary drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs.

Uplift Securitization Proceeds Receivable from ERCOT — As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were uplifted and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri.

In October 2021, the PUCT issued a Debt Obligation Order approving $ 2.1 billion financing and the methodology for allocation of proceeds to the LSEs.

In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we expect to receive approximately $ 544 million of proceeds from ERCOT.

The Company accounted for the proceeds we will receive by analogy to the contribution model within Accounting Standards Codification (ASC) 958-605, Not-for-Profit Entities - Revenue Recognition and the grant model within International Accounting Standard 20, Accounting for Government Grants and Disclosure of Government Assistance , as a reduction to expenses in the statements of operations in the annual period for which the proceeds are intended to compensate.

The proceeds are expected to be received from ERCOT in the second quarter of 2022, and we concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $ 2.1 billion funding approved in the Debt Obligation Order.

The associated expense reduction is reflected in fuel, purchased power costs and delivery fees within our consolidated statements of operations as that is where the initial costs for which we are being compensated were recorded.

The final financial impact of Winter Storm Uri continues to be subject to the outcome of potential litigation arising from the event, or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain ( i.e.

, fuel supply, wholesale pricing of generation, or allocating the financial impacts of market-wide load shed ratably across all retail market participants), that is currently being considered or may be considered by any such parties.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and U.S.

In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and the U.S.

Government declared the COVID-19 outbreak a national emergency.

3 unchanged sentences

The Company's consolidated financial statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and reported amounts of revenue and expenses during the reporting periods presented.

The Company considered the impact of COVID-19 on the assumptions and estimates used and determined that there have been no material adverse impacts on the Company's results of operations for the year ended December 31, 2020.

In response to the global pandemic related to COVID-19, the CARES Act was signed into law on March 27, 2020.

In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020.

See Note 7 for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.

February 2021 Weather Event

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas.

At the time we issued these financial statements, we expect the impact of the weather event to be a material loss that will be reflected in our first quarter 2021 results of operations.

However, uncertainty exists with respect to the financial impact of the weather event due in part to outstanding pricing and settlement data from ERCOT, the outcome of potential litigation arising from the event, or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain (i.e.

fuel supply, wholesale pricing of generation, or allocating the financial impacts of market-wide load shed ratably across all retail market participants), that is currently being considered or may be considered by any such parties.

Recent Developments

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

See below and Note 14 for more information concerning the Series B Preferred Stock, which was issued in December 2021 under the Green Finance Framework.

Series B Preferred Stock Offering — On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Network.

The net proceeds of the Series B Offering were approximately $ 985 million, after deducting underwriting commissions and offering expenses.

We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.

See Note 14 for more information concerning the Series B Preferred Stock.

Commodity-Linked Revolving Credit Facility — On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent.

The Credit Agreement provides for a $ 1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility).

Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes.

See Note 11 for more information concerning the Commodity-Linked Facility.

Basis of Presentation

19 unchanged sentences

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met.

At December 31, 2020 and 2019, there were no derivative positions accounted for as cash flow or fair value hedges.

As of December 31, 2021 and 2020, there were no derivative positions accounted for as cash flow or fair value hedges.

We report commodity hedging and trading results as revenue, fuel expense or purchased power in the consolidated statements of operations depending on the type of activity.

14 unchanged sentences

We expense advertising costs as incurred and include them within SG&A expenses.

Advertising expenses totaled $ 43 million, $ 49 million and $ 46 million for the year ended December 31, 2020, 2019 and 2018, respectively.

Advertising expenses totaled $ 48 million, $ 43 million and $ 49 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Impairment of Long-Lived Assets

3 unchanged sentences

Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable.

See Note 21 for details of impairments of long-lived assets recorded in 2020.

See Note 21 for details of impairments of long-lived assets recorded in 2021 and 2020.

Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects.

11 unchanged sentences

Defined Benefit Pension Plans and OPEB Plans

On the Merger Date, Vistra assumed the pension and OPEB plans that Dynegy had provided to certain of its eligible employees and retirees.

The excess of the benefit obligations over the fair value of plan assets was recognized as a liability.

See Note 2 for additional information regarding the Merger.

Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employee from the company.

16 unchanged sentences

We report franchise and revenue-based taxes in SG&A expense in our consolidated statements of operations.

On the Merger Date, Vistra and Dynegy effected a merger transaction that for tax purposes was treated as a tax-free reorganization in which Vistra survived as the parent entity.

In general, all of Dynegy's tax basis and attributes were transferred to Vistra, including approximately $ 4.5 billion of utilizable NOLs and refundable alternative minimum tax (AMT) tax credits.

Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of our solar and battery storage facilities of zero , $ 2 million and $ 78 million and a corresponding increase in the deferred tax assets in 2020, 2019 and 2018, respectively.

Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of our solar and battery storage facilities of zero , zero and $ 2 million and a corresponding increase in the deferred tax assets in 2021, 2020 and 2019, respectively.

Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules.

44 unchanged sentences

See Note 21 for discussion of these and other investments.

Unconsolidated Investments

We use the equity method of accounting for investments in affiliates over which we exercise significant influence.

Our share of net income from these affiliates is recorded to equity in earnings of unconsolidated investment in the consolidated statements of operations.

Noncontrolling Interest

34 unchanged sentences

Leases — On January 1, 2019, we adopted Accounting Standards Update (ASU) 2016-02, Leases (Topic 842) and all related amendments (new lease standard) using the modified retrospective method with the cumulative-effect adjustment to the opening balance of retained deficit for all contracts outstanding at the time of adoption.

The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.

We expect the impact of the adoption of the new lease standard to be immaterial to our net income on an ongoing basis.

The impact of adopting the new lease standard primarily relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases.

Under the new lease standard, each ROU asset will be amortized over the lease term and liability settled at the end of the lease term.

The impact of the adoption of the new lease standard is immaterial to our net income on an ongoing basis.

The primary impact of adopting the new lease standard relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases.

We recognized the effect of initially applying the new lease standard by recording ROU assets of $ 85 million and lease liabilities of $ 123 million in our consolidated balance sheet.

See Note 12 for the disclosures required by the new lease standard.

Changes to the Disclosure Requirements for Defined Benefit Plans — In August 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans.

The ASU removes disclosure requirements for (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year, (b) related party disclosures about the amount of future annual benefits covered by insurance and annuity contracts and significant transactions between the employer or related parties and the plan and (c) the effects of a one-percentage-point change in assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic benefit costs and benefit obligation for postretirement health care benefits.

The ASU requires new disclosures for (a) the weighted-average interest crediting rates for cash balance plans and other plans with promised interest crediting rates and (b) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period.

We adopted this ASU in the fourth quarter of 2018, and the updated disclosures are included in Note 17.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income — In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income .

The ASU permits the reclassification of income tax effects of the TCJA on items within accumulated other comprehensive income (AOCI) to retained earnings.

We adopted this ASU in the fourth quarter of 2018, and the impact was additional tax expense to AOCI of $ 1 million with the offset to retained deficit (see Note 7).

Revenue from Contracts with Customers — On January 1, 2018, we adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) and all related amendments (new revenue standard) using the modified retrospective method for all contracts outstanding at the time of adoption.

We recognized the cumulative effect of initially applying the revenue standard as an adjustment to the opening balance of retained deficit.

The impact of the adoption of the revenue standard was immaterial and we expect the adoption to continue to be immaterial to our net income on an ongoing basis.

Our retail energy charges and wholesale generation, capacity and contract revenues will continue to be recognized when electricity and other services are delivered to our customers.

The impact of adopting the revenue standard primarily relates to the deferral of acquisition costs associated with retail contracts with customers that were previously expensed as incurred.

Under the revenue standard, these amounts are capitalized and amortized over the expected life of the customer.

Adoption of Accounting Standards Issued in 2020

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):

10 unchanged sentences

33-10762 , to reflect the SEC's new disclosure rules on guaranteed debt securities adopted by the Company.

ACQUISITIONS, MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING

ACQUISITIONS AND BUSINESS COMBINATION ACCOUNTING

Ambit Transaction

26 unchanged sentences

Purchase Price

Allocation Measurement Period Adjustments recorded through September 30, 2020 Final

Allocation Measurement Period Adjustments recorded Final

Purchase Price

Allocation Measurement Period Adjustments recorded through June 30, 2020

Allocation Measurement Period Adjustments recorded

Cash and cash equivalents $ 49 $ — $ 26 $ —

17 unchanged sentences

The net income acquired in the Ambit Transaction and Crius Transaction include intangible amortization and transition related expenses.

Ambit and Crius Transaction Unaudited Pro Forma Financial Information — The following unaudited consolidated pro forma financial information for the years ended December 31, 2019 and 2018 assumes that the Ambit and Crius Transactions occurred on January 1, 2018 (i.e., represents our results for the years ended December 31, 2019 and 2018 plus the results for either Ambit Transaction or Crius Transaction for the period not owned by us, respectively).

Ambit and Crius Transaction Unaudited Pro Forma Financial Information — The following unaudited consolidated pro forma financial information for the year ended December 31, 2019 assumes that the Ambit and Crius Transactions occurred on January 1, 2019 (i.e., represents our results for the year ended December 31, 2019 plus the results for either Ambit Transaction or Crius Transaction for the period not owned by us, respectively).

The unaudited consolidated pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Ambit Transaction and Crius Transaction been completed on January 1, 2019, nor is the unaudited consolidated pro forma financial information indicative of future results of operations, which may differ materially from the consolidated pro forma financial information presented here.

1 unchanged sentence

Year Ended December 31, 2019 Year Ended December 31, 2019

2019 2018 2019 2018

Revenues $ 12,931 $ 12,373

Net income (loss) (a) $ 949 $ ( 95 ) $ 876 $ ( 43 )

Net income (loss) attributable to Vistra $ 951 $ ( 93 ) $ 878 $ ( 41 )

Net income (loss) attributable to Vistra per weighted average share of common stock outstanding — basic $ 1.92 $ ( 0.18 ) $ 1.78 $ ( 0.08 )

Net income (loss) attributable to Vistra per weighted average share of common stock outstanding — diluted $ 1.90 $ ( 0.18 ) $ 1.76 $ ( 0.08 )

Net income (a) $ 949 $ 876

Net income attributable to Vistra $ 951 $ 878

Net income attributable to Vistra per weighted average share of common stock outstanding — basic $ 1.92 $ 1.78

Net income attributable to Vistra per weighted average share of common stock outstanding — diluted $ 1.90 $ 1.76

(a) Decrease in pro forma net income compared to consolidated net income is driven by unrealized losses on hedging activities of Crius and amortization of intangible assets.

The consolidated unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired and the related impacts on tax expense.

Dynegy Merger Transaction

On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement.

Pursuant to the Merger Agreement, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation.

The Merger was intended to qualify as a tax-free reorganization under the IRC, so that none of Vistra, Dynegy or any of the Dynegy stockholders would recognize any gain or loss in the transaction, except that Dynegy stockholders could recognize a gain or loss with respect to cash received in lieu of fractional shares of Vistra's common stock.

Vistra is the acquirer for both federal tax and accounting purposes.

On the Merger Date, each issued and outstanding share of Dynegy common stock, par value $ 0.01 per share, other than shares owned by Vistra or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, was automatically converted into 0.652 shares of common stock, par value $ 0.01 per share, of Vistra (the Exchange Ratio), except that cash was paid in lieu of fractional shares, which resulted in Vistra issuing 94,409,573 shares of Vistra common stock to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units and warrants.

The total number of Vistra shares outstanding at the close of the Merger was 522,932,453 shares.

Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra's common stock, after giving effect to the Exchange Ratio.

Dynegy Business Combination Accounting

We believe the Merger has provided and continues to provide significant strategic benefits and opportunities to Vistra, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flows.

The Merger was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date.

The combined results of operations are reported in our consolidated financial statements beginning as of the Merger Date.

A summary of the techniques used to estimate the fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 15), is listed below:

• Working capital was valued using available market information (Level 2).

• Acquired property, plant and equipment was valued using a combination of an income approach and a market approach.

The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).

• Acquired derivatives were valued using the methods described in Note 15 (Level 1, Level 2 or Level 3).

• Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis (Level 3).

The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference discounted to present value and recorded as either an intangible asset or liability.

• Long-term debt was valued using a market approach (Level 2).

• AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).

The following table summarizes the consideration paid and the final allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date.

Based on the opening price of Vistra common stock on the Merger Date, the purchase price was approximately $ 2.3 billion.

During the three months ended March 31, 2019, the purchase price allocation was completed.

During the period from April 9, 2018 through March 31, 2019, we updated the initial purchase price allocation with final valuations by increasing property, plant and equipment by $ 173 million, decreasing intangible assets by $ 36 million, increasing goodwill by $ 175 million, decreasing accounts receivable, inventory, prepaid expenses and other current assets by $ 10 million, increasing accumulated deferred tax asset by $ 127 million, decreasing other noncurrent assets by $ 113 million, increasing trade accounts payable and other current liabilities by $ 89 million, increasing other noncurrent liabilities by $ 177 million, increasing asset retirement obligations, including amounts due currently by $ 56 million as well as other minor adjustments.

The valuation revisions were a result of updated inputs used in determining the fair value of the acquired assets and liabilities.

Dynegy shares outstanding as of April 9, 2018 (in millions) 144.8

Exchange Ratio 0.652

Vistra shares issued for Dynegy shares outstanding (in millions) 94.4

Opening price of Vistra common stock on April 9, 2018 $ 19.87

Purchase price for common stock $ 1,876

Fair value of equity component of tangible equity units 369

Fair value of outstanding stock compensation awards attributable to pre-combination service 26

Fair value of outstanding warrants 2

Total purchase price $ 2,273

Dynegy Merger Final Purchase Price Allocation

Cash and cash equivalents $ 445

Trade accounts receivables, inventories, prepaid expenses and other current assets 853

Property, plant and equipment 10,535

Accumulated deferred income taxes 518

Identifiable intangible assets 351

Other noncurrent assets 419

Total assets acquired 13,296

Trade accounts payable and other current liabilities 733

Commodity and other derivative contractual assets and liabilities, net 422

Asset retirement obligations, including amounts due currently 475

Long-term debt, including amounts due currently 8,919

Other noncurrent liabilities 469

Total liabilities assumed 11,018

Identifiable net assets acquired 2,278

Noncontrolling interest in subsidiary 5

Total purchase price $ 2,273

Acquisition costs incurred in the Merger totaled less than $1 million and $ 25 million for the years ended December 31, 2019 and 2018, respectively.

For the period from the Merger Date through December 31, 2018, our consolidated statements of operations include revenues and net income (loss) acquired in the Merger totaling $ 3.902 billion and $ 224 million respectively.

Dynegy Merger Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the year ended December 31, 2018 assumes that the Merger occurred on January 1, 2018.

The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Merger been completed on January 1, 2018, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.

Year Ended December 31, 2018

Revenues $ 10,595

Net loss $ ( 268 )

Net loss attributable to Vistra $ ( 265 )

Net loss attributable to Vistra per weighted average share of common stock outstanding — basic $ ( 0.52 )

Net loss attributable to Vistra per weighted average share of common stock outstanding — diluted $ ( 0.52 )

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Merger, effects of the Merger on tax expense (benefit), changes in the expected impacts of the tax receivable agreement due to the Merger, and other related adjustments.

ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES

DEVELOPMENT OF GENERATION FACILITIES

Texas Segment Solar Generation and Energy Storage Projects

In September 2020, we announced the planned development of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas.

Estimated commercial operation dates for these facilities range from Summer 2021 to Fall 2022.

Upton 2 Phase I — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas (Upton 2).

As part of this project, we entered into a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility.

We spent approximately $ 231 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights.

The facility began test operations in March 2018 and commercial operations began in June 2018.

Upton 2 Phase II — In 2018, we completed the construction of our first battery energy storage system (ESS).

In October 2018, we were awarded a $ 1 million grant from the TCEQ for our battery ESS at our Upton 2 solar facility.

The grant is part of the Texas Emissions Reduction Plan.

The 10 MW lithium-ion ESS captures excess solar energy produced during the day and releases the energy in late afternoon and early evening, when demand is highest.

The Upton 2 Phase II battery ESS became operational in December 2018.

We have announced our planned development of up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas.

The first 158 MW of solar generation came online in January and February 2022.

Estimated commercial operation dates for the remaining facilities range from the second quarter of 2022 to fourth quarter of 2023.

As of December 31, 2021, we had accumulated approximately $ 286 million in construction-work-in-process for these Texas segment solar generation and battery ESS projects.

East Segment Solar Generation and Energy Storage Projects

In September 2021, we announced the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act.

Estimated commercial operation dates for these facilities range from 2023 to 2025.

West Segment Energy Storage Projects

2 unchanged sentences

The contract was amended to increase the capacity of the planned development to a 36.25 MW battery ESS.

In April 2020, the concurrent local area reliability service agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed and sent to the California Public Utilities Commission (CPUC) for approval, which is expected prior to the second quarter of 2021.

The battery ESS project is expected to enter commercial operations by January 2022.

In April 2020, the concurrent Local Area Reliability Service (LARS) agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed, but required California Public Utilities Commission (CPUC) approval.

PG&E did not receive CPUC approval as of April 15, 2021.

On April 16, 2021, Vistra terminated the LARS agreement with PG&E.

We are continuing development of the Oakland battery ESS project while seeking another contractual arrangement that will allow the investment to move forward.

Moss Landing — In June 2018, we announced that, subject to approval by the CPUC, we would enter into a 20 -year resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California (Moss Landing Phase I).

PG&E filed its application with the CPUC in June 2018 and the CPUC approved the resource adequacy contract in November 2018.

At December 31, 2020, we had accumulated approximately $ 370 million in construction work-in-process for Moss Landing Phase I.

Under the contract, PG&E will pay us a fixed monthly resource adequacy payment, while we will receive the energy revenues and incur the costs from dispatching and charging the ESS.

Moss Landing Phase I began test operations in December 2020 and is expected to be fully operational by April 2021.

PG&E filed for Chapter 11 bankruptcy protection in January 2019.

In November 2019, the bankruptcy court approved PG&E's motion requesting approval of the assumption of the resource adequacy contract subject to the CPUC approving the terms of an amendment to the resource adequacy contract, and the CPUC approved the terms of the amendment in January 2020.

PG&E emerged from bankruptcy protection in July 2020.

Moss Landing Phase I commenced commercial operations in May 2021.

In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10 -year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II).

PG&E filed its application with the CPUC in May 2020 and the CPUC approved the resource adequacy contract in August 2020.

At December 31, 2020, we had accumulated approximately $ 29 million in construction work-in-process for Moss Landing Phase II.

We anticipate Moss Landing Phase II will commence commercial operations in the third quarter of 2021.

Moss Landing Phase II commenced commercial operations in July 2021.

The total development costs for Moss Landing Phases I and II totaled approximately $ 600 million.

In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15 -year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III).

PG&E filed its application with the CPUC in January 2022, and CPUC approval is expected in the second quarter of 2022.

Moss Landing Phase III is expected to enter commercial operations in the summer of 2023.

Moss Landing Outages — In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS.

A review found that only a small, single-digit percentage of batteries at the facility were impacted and that the root cause originated in systems separate from the battery system.

The facility will be offline as we perform the work necessary to return the facility to service.

Moss Landing Phase II was not affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery ESS.

An investigation is underway to determine the root cause of the incident.

The facility will be offline as we perform the work necessary to return the facility to service.

Moss Landing Phase I was not affected by the incident, but the facility will remain offline during the assessment stage of the Moss Landing Phase II incident.

We do not expect these incidents to have a material impact on our results of operations.

RETIREMENT OF GENERATION FACILITIES

2020 Announcements

In December 2020, we announced our intention to retire two natural gas facilities in Texas due to their age, cost profile and small scale, as well as low power prices, limited operational windows and substantial costs to repair, maintain and upgrade the facilities.

Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Dates Units Retired or

Expected Retirement Date

Wharton Boling, TX ERCOT Natural Gas 83 November 30, 2020

Trinidad Trinidad, TX ERCOT Natural Gas 244 By April 30, 2021

In September 2020 and December 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 13), and in furtherance of our efforts to significantly reduce our carbon footprint.

Expected plant retirement expenses of $ 43 million, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our Sunset segment.

Operational results for plants with planned retirements are included in our Sunset segment beginning in the quarter when a retirement plan is announced.

See Note 21 for discussion of impairments recorded in connection with these announcements.

Sunset Segment

Operational results for plants with defined retirement dates identified below are included in our Sunset segment beginning in the quarter when a retirement plan is announced.

Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Expected Retirement Date (a)

1 unchanged sentence

Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027

Joppa Joppa, IL MISO Coal 802 By the end of 2025

Joppa Joppa, IL MISO Natural Gas 221 By the end of 2025

Edwards Bartonville, IL MISO Coal 585 By the end of 2022

Joppa Joppa, IL MISO Coal 802 By September 1, 2022

Joppa Joppa, IL MISO Natural Gas 221 By September 1, 2022

Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027

1 unchanged sentence

Newton Newton, IL MISO/PJM Coal 615 By the end of 2027

Zimmer Moscow, OH PJM Coal 1,300 By the end of 2027

Zimmer Moscow, OH PJM Coal 1,300 By May 31, 2022

(a) Generation facilities may retire earlier than expected dates if economic or other conditions dictate.

2019 Announcements

In September 2019, we announced the settlement of a lawsuit alleging violations of opacity and particulate matter limits at our Edwards facility in Bartonville, Illinois.

1 unchanged sentence

District Court for the Central District of Illinois in November 2019, we will retire the Edwards facility by the end of 2022 (see Note 13).

In August 2019, we announced the planned retirement of four additional power plants in Illinois with a total installed nameplate generation capacity of 2,068 MW.

We retired these units due to changes in the Illinois multi-pollutant standard rule (MPS rule) that require us to retire approximately 2,000 MW of generation capacity (see Note 13).

In light of the provisions of the Federal Power Act and the FERC regulations thereunder, the affected subsidiaries of Vistra identified the retired units by analyzing the economics of each of our Illinois plants and designating the least economic units for retirement.

Expected plant retirement expenses of $ 47 million, driven by severance costs, were accrued in the year ended December 31, 2019 and were included primarily in operating costs of our Asset Closure segment.

In August 2019, we remeasured our pension and OPEB plans resulting in an increase to the benefit obligation liability of $ 21 million, pretax other comprehensive loss of $ 18 million and curtailment expense of $ 3 million recognized as other deductions in our consolidated statements of operations.

The following table details the units in Illinois totaling 2,653 MW that have been or will be retired.

Operational results for the four retired plants identified below are included in the Asset Closure segment, which is engaged in the decommissioning and reclamation of retired plants and mines.

Operational results for the Edwards facility are included in the Sunset segment.

Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Dates Units Retired or

Expected Retirement Date

Expected plant retirement expenses of $ 43 million, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our Sunset segment.

In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018 (see Note 13).

We had previously announced that Joppa would retire no later than the end of 2027.

In July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022 due to the inability to secure capacity revenues for the plant in the latest PJM capacity auction held in May 2021.

We had previously announced that Zimmer would retire no later than the end of 2027.

See Note 21 for discussion of impairments recorded in connection with these announcements.

Asset Closure Segment

Operational results for the Illinois plants retired in 2019 identified below are included in the Asset Closure segment.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines, including those retired prior to 2019.

Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Dates Units Retired

Coffeen Coffeen, IL MISO Coal 915 November 1, 2019

2 unchanged sentences

Hennepin Hennepin, IL MISO Coal 294 November 1, 2019

Edwards Bartonville, IL MISO Coal 585 By the end of 2022

2018 Announcements

In August 2018, we filed a notice of suspension of operation with PJM and other mandatory regulatory notifications related to the retirement of our 51 MW Northeastern Power Company waste coal facility in McAdoo, Pennsylvania (Northeastern Facility).

We decided to retire the Northeastern Facility due to its uneconomic operations and financial outlook.

Following the receipt of regulatory approvals, the Northeastern Facility was retired in October 2018.

The decision to retire the Northeastern Facility did not result in a material impact to the financial statements, and the operational results of the Northeastern Facility are included in our Asset Closure segment.

Two of our non-operated, jointly held power plants acquired in the Merger, for which our proportional generation capacity was 883 MW, were retired in May 2018.

These units were retired as previously scheduled.

No gain or loss was recorded in conjunction with the retirement of these units, and the operational results of these facilities are included in our Asset Closure segment.

The following table details the units retired.

Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Ownership Interest Date Units Retired

Killen Manchester, Ohio PJM Coal 204 33 % May 31, 2018

Stuart Aberdeen, Ohio PJM Coal 679 39 % May 24, 2018

In January and February 2018, we retired three power plants in Texas with a total installed nameplate generation capacity of 4,167 MW.

We decided to retire these units because they were projected to be uneconomic based on then current market conditions and would have faced significant environmental costs associated with operating such units.

In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement.

Expected retirement expenses were accrued in the third and fourth quarter of 2017 and, as a result, no retirement expenses were recorded related to these facilities in the year ended December 31, 2018.

The operational results of these facilities are included in our Asset Closure segment.

The following table details the units retired.

Name Location (all in the state of Texas) ISO/RTO Fuel Type Installed Nameplate Generation Capacity (MW) Date Units Retired

Monticello Titus County ERCOT Lignite/Coal 1,880 January 4, 2018

Sandow Milam County ERCOT Lignite 1,137 January 11, 2018

Big Brown Freestone County ERCOT Lignite/Coal 1,150 February 12, 2018

In August 2019, we announced the planned retirement of four power plants in Illinois with a total installed nameplate generation capacity of 2,068 MW.

We retired these units due to changes in the Illinois Multi-Pollutant Standard rule (MPS rule) that require us to retire approximately 2,000 MW of generation capacity.

The following tables disaggregate our revenue by major source:

11 unchanged sentences

Hedging and other revenues (b) ( 115 ) ( 4,355 ) 123 35 ( 1,371 ) — — ( 5,683 )

Affiliate sales — 2,999 1,595 3 298 — ( 4,895 ) —

Affiliate sales (c) — 1,035 1,024 5 220 — ( 2,284 ) —

Total other revenues ( 117 ) ( 3,320 ) 1,221 40 ( 1,163 ) — ( 2,284 ) ( 5,623 )

1 unchanged sentence

(a) Represents net capacity sold (purchased) in each ISO/RTO.

The East segment includes net purchases of capacity in the PJM market and the Sunset segment includes net sales of capacity in the PJM market.

(b) Includes $ 164 million of unrealized net gains from mark-to-market valuations of commodity positions.

The East segment includes $ 470 million of capacity purchased offset by $ 448 million of capacity sold.

The Sunset segment includes $ 4 million of capacity purchased offset by $ 188 million of capacity sold.

(b) Includes $ 1.191 billion of unrealized net losses from mark-to-market valuations of commodity positions.

See Note 20 for unrealized net gains (losses) by segment.

(c) Texas and East segments include $ 1.028 billion and $ 529 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2020

4 unchanged sentences

Wholesale generation revenue from ISO/RTO — 475 310 124 473 1 — 1,383

Capacity revenue from ISO/RTO — — 170 — 197 11 — 378

Capacity revenue from ISO/RTO (a) — — ( 52 ) — 164 — — 112

Revenue from other wholesale contracts — 226 668 54 187 1 — 1,136

2 unchanged sentences

Intangible amortization ( 5 ) — 2 — ( 21 ) — — ( 24 )

Hedging and other revenues (a) 86 ( 250 ) 37 132 247 42 — 294

Hedging and other revenues (b) 56 416 ( 108 ) 101 151 1 — 617

Affiliate sales — 2,999 1,595 3 298 — ( 4,895 ) —

1 unchanged sentence

Total revenues $ 8,270 $ 4,116 $ 2,415 $ 282 $ 1,252 $ 3 $ ( 4,895 ) $ 11,443

(a) Includes $ 682 million of unrealized net gains from mark-to-market valuations of commodity positions.

(a) Represents net capacity sold (purchased) in each ISO/RTO.

The East segment includes $ 542 million of capacity purchased offset by $ 490 million of capacity sold.

The Sunset segment includes $ 3 million of capacity purchased offset by $ 167 million of capacity sold.

(b) Includes $ 164 million of unrealized net gains from mark-to-market valuations of commodity positions.

See Note 20 for unrealized net gains (losses) by segment.

5 unchanged sentences

Wholesale generation revenue from ISO/RTO — 1,477 629 193 751 194 — 3,244

Capacity revenue from ISO/RTO — — 376 30 258 34 — 698

Capacity revenue from ISO/RTO (a) — — 170 — 197 11 — 378

Revenue from other wholesale contracts — 264 702 9 147 2 — 1,124

2 unchanged sentences

Intangible amortization ( 15 ) — ( 4 ) 4 ( 17 ) — — ( 32 )

Hedging and other revenues (a) 74 ( 387 ) 16 5 ( 214 ) ( 106 ) 2 ( 610 )

Hedging and other revenues (b) 86 ( 250 ) 37 132 247 42 — 294

Affiliate sales — 2,345 1,256 — 277 92 ( 3,970 ) —

1 unchanged sentence

Total revenues $ 6,872 $ 3,836 $ 2,790 $ 338 $ 1,602 $ 341 $ ( 3,970 ) $ 11,809

(a) Includes $ 380 million of unrealized net losses from mark-to-market valuations of commodity positions.

(a) Represents net capacity sold (purchased) in each ISO/RTO.

The East segment includes $ 443 million of capacity purchased offset by $ 613 million of capacity sold.

The Sunset segment includes $ 1 million of capacity purchased offset by $ 198 million of capacity sold.

(b) Includes $ 682 million of unrealized net gains from mark-to-market valuations of commodity positions.

See Note 20 for unrealized net gains (losses) by segment.

38 unchanged sentences

The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates.

The deferred acquisition and contract cost balance as of December 31, 2020, 2019 and 2018 and January 1, 2018 was $ 80 million, $ 53 million, $ 38 million and $ 22 million, respectively.

The amortization related to these costs during the year ended December 31, 2020 and 2019 totaled $ 46 million and $ 21 million, respectively, recorded as SG&A expenses, and $ 7 million and $ 9 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.

The deferred acquisition and contract cost balance as of both December 31, 2021 and 2020 was $ 80 million.

The amortization related to these costs during the year ended December 31, 2021, 2020 and 2019 totaled $ 75 million, $ 46 million and $ 21 million respectively, recorded as SG&A expenses, and $ 6 million, $ 7 million and $ 9 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.

Practical Expedients

16 unchanged sentences

The following table provides information regarding our goodwill balance.

There have been no impairments of goodwill since Emergence.

Balance at December 31, 2018 $ 2,068

5 unchanged sentences

Measurement period adjustments recorded in connection with the Ambit Transaction 44

Balance at December 31, 2020 $ 2,583

At December 31, 2020, the goodwill balance of $ 2.583 billion consisted of the following:

Balance at December 31, 2021 and 2020 $ 2,583

As of December 31, 2021, the carrying value of goodwill totaled $ 2.583 billion and consisted of the following:

• $ 1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our Retail reporting unit.

24 unchanged sentences

Total identifiable intangible assets subject to amortization $ 2,870 $ 2,065 805 $ 2,915 $ 1,844 1,071

Retail trade names (not subject to amortization) 1,374 1,391

Retail trade names (not subject to amortization) (c) 1,341 1,374

Mineral interests (not currently subject to amortization) — 1

Total identifiable intangible assets $ 2,146 $ 2,446

(a) At December 31, 2020, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization.

(a) As of December 31, 2021 and 2020, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization.

(b) Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).

(c) During the year ended December 31, 2021, we recorded a $ 33 million impairment to a retail trade name intangible asset.

Identifiable intangible liabilities are comprised of the following:

21 unchanged sentences

• Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

• Retail trade names — Our retail trade name intangible asset represents the fair value of our retail brands, including the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power and U.S.

Gas & Electric, and was determined to be an indefinite-lived asset not subject to amortization.

This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets.

Significant assumptions included within the development of the fair value estimate include estimated gross margins for future periods and implied royalty rates.

On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2020.

• Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power and U.S.

Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization.

These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets.

Significant assumptions included within the development of the fair value estimates include estimated gross margins for future periods and implied royalty rates.

On the most recent testing date, we recorded an impairment charge for $ 33 million related to an immaterial trade name.

For all other trade names, we determined it was more likely than not that the fair value of the retail trade name intangible assets exceeded their carrying values at October 1, 2021.

• Retail and wholesale contracts/purchase and sale contracts — These intangible assets represent the value of various retail and wholesale contracts and purchase and sale contracts.

34 unchanged sentences

Federal and State return to provision adjustment ( 2 ) 13 ( 17 )

Remeasurement of historical Vistra deferred taxes for expanded state footprint — — ( 54 )

Effect of refundable minimum tax credits no longer subject to sequestration — — ( 15 )

Nondeductible compensation 4 — 3

22 unchanged sentences

Net Deferred Income Tax Asset $ 1,302 $ 837

At December 31, 2020, we had total deferred tax assets of approximately $ 837 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as federal and state net operating loss (NOL) carryforwards.

Our deferred tax assets were significantly impacted by the Merger.

As of December 31, 2021, we had total deferred tax assets of approximately $ 1.302 billion that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as federal and state net operating loss (NOL) carryforwards.

Our deferred tax assets were significantly impacted by the impacts of Winter Storm Uri as well as the Merger.

For the year ended December 31, 2021, we recognized a tax benefit of $ 74 million on the release of state valuation allowances largely related to Illinois.

Illinois enacted legislation in 2021 extending the carryforward period of net operating losses and we forecast to utilize all losses before expiration.

For the year ended December 31, 2020, we recognized a partial valuation allowance of $ 32 million on the net operating loss carryforwards related largely to Illinois and New York due to forecasted expiration.

1 unchanged sentence

In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required.

At December 31, 2020, we had $ 3.4 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2032.

At December 31, 2020, we had no remaining AMT credits refundable through the TCJA available.

The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax asset of $ 5 million and $ 3 million at December 31, 2020 and 2019, respectively.

As of December 31, 2021, we had $ 4.5 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2032.

As of December 31, 2021, we had no remaining AMT credits refundable through the TCJA available.

The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax liability of $ 9 million at December 31, 2021 and a net deferred tax asset of $ 5 million at December 31, 2020.

Coronavirus Aid, Relief, and Economic Security Act (CARES Act) and Final Section 163(j) Regulations

2 unchanged sentences

Additionally, the final Section 163(j) regulations were issued in July 2020 and provided a critical correction to the proposed regulations with respect to the computation of adjusted taxable income.

Vistra received $ 64 million in 2020 relating to the acceleration of AMT refunds and an approximate $ 350 million increase in interest expense deduction over the 2019 and 2020 tax years under the cumulative impact of these final laws and regulation pertaining to Section 163(j).

Additionally, Vistra expects to receive an approximate $ 305 million increase in interest expense deduction in the 2021 tax year under the final Section 163(j) regulations.

We do not anticipate a material impact to the effective tax rate from these impacts.

In 2021, Vistra is benefiting from the final 163(j) regulations and able to utilize its remaining 163(j) carryforward of $ 12 million.

Certain provisions in the final 163(j) regulations begin to sunset in 2022, for which Vistra will continue its legislative monitoring and advocacy efforts to amend consistent with the intent of the law, including the permanent addback of depreciation and amortization to adjusted taxable income.

Vistra is also utilizing the CARES Act payroll deferral mechanism to defer the payment of approximately $ 22 million from 2020 to 2021 and 2022.

We paid approximately half of the previously deferred taxes in December 2021.

Liability for Uncertain Tax Positions

6 unchanged sentences

Balance at beginning of period, excluding interest and penalties $ 39 $ 126 $ 39

Additions allocated in the Merger — — 39

Additions based on tax positions related to prior years 1 3 3

4 unchanged sentences

Vistra and its subsidiaries file income tax returns in U.S.

federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities.

The IRS has notified us of its intention to open an audit regarding the 2018 tax year.

federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities.

In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019 and an employment tax audit for tax year 2018.

Crius is currently under audit by the IRS for the tax years 2015 and 2016.

Uncertain tax positions totaling $ 39 million at December 31, 2020 reflect the final regulations under Section 163(j) that were released in July 2020, and we have adjusted deferred tax assets and liabilities by $ 87 million in the year ended December 31, 2020.

Uncertain tax positions totaling $ 39 million at December 31, 2018 arose in connection with the Merger as discussed in Note 2.

Uncertain tax positions totaled $ 38 million at December 31, 2021.

Tax Matters Agreement

30 unchanged sentences

Noncurrent TRA obligation at the end of the period $ 394 $ 447 $ 455

(a) During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA obligation totaling $ 69 million as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) regulations and the anticipated tax benefits from renewable development projects.

During the year ended December 31, 2019, we recorded a decrease to the carrying value of the TRA obligation totaling approximately $ 22 million as a result of adjustments to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra's state income tax profile, including the Dynegy, Crius and Ambit acquisitions.

During the year ended December 31, 2018, we recorded an increase to the carrying value of the TRA obligation totaling $ 14 million related to changes in the timing of estimated payments resulting changes in the timing of estimated payments and new multistate tax impacts resulting from the Merger.

(a) During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $ 115 million as a result of adjustments to forecasted taxable income, including the financial impacts of Winter Storm Uri, and anticipated tax benefits available under current tax laws for planned additional renewable development projects.

During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA obligation totaling approximately $ 69 million as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) regulations and the anticipated tax benefits from renewable development projects.

During the year ended December 31, 2019, we recorded an decrease to the carrying value of the TRA obligation totaling $ 22 million as a result of adjustments to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra's state income tax profile, including the Dynegy, Crius and Ambit acquisitions.

As of December 31, 2021, the estimated carrying value of the TRA obligation totaled $ 395 million, which represents the discounted amount of projected payments under the TRA.

1 unchanged sentence

Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business.

The estimates of future business results include assumptions related to renewable development projects that Vistra is planning to execute that generate significant tax benefits.

These benefits have a material impact on the timing of TRA obligation payments.

These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation.

7 unchanged sentences

2021 2020 2019

Net income (loss) attributable to Vistra $ ( 1,274 ) $ 636 $ 928

Less cumulative dividends attributable to Series A Preferred Stock ( 17 ) — —

Less cumulative dividends attributable to Series B Preferred Stock ( 4 ) — —

Net income (loss) attributable to common stock — basic ( 1,295 ) 636 928

9 unchanged sentences

TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers).

The Receivables Facility was renewed in July 2020, extending the term of the Receivables Facility to July 2021, with the ability to borrow $ 550 million beginning with the settlement date in July 2020 until the settlement date in August 2020, $ 625 million from the settlement date in August 2020 until the settlement date in November 2020, $ 550 million from the settlement date in November 2020 until the settlement date in December 2020 and $ 450 million thereafter for the remaining term of the Receivables Facility.

In December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and TriEagle Energy, as originators, and increase the commitment of the Purchasers to $ 500 million for the remaining term of the Receivables Facility.

In February 2021, the Receivables Facility was amended to allow for a one-time, $ 596 million borrowing to take advantage of a higher receivable balance at such time.

The borrowing limit is expected to return to $ 500 million in March 2021.

The borrowing limit returned to $ 500 million in March 2021.

In March 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $ 600 million through the July 2021 renewal.

The Receivables Facility was renewed in July 2021, extending the term of the Receivables Facility to July 2022, with the ability to borrow $ 600 million beginning with the settlement date in July 2021 until the settlement date in August 2021, $ 725 million from the settlement date in August 2021 until the settlement date in November 2021 and $ 600 million from the settlement date in November 2021 and thereafter for the remaining term of the Receivables Facility.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy.

6 unchanged sentences

TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.

As of December 31, 2020, outstanding borrowings under the receivables facility totaled $ 300 million and were supported by $ 735 million of RecCo gross receivables.

As of December 31, 2021, there were no outstanding borrowings under the Receivables Facility.

As of December 31, 2020, outstanding borrowings under the Receivables Facility totaled $ 300 million and were supported by $ 735 million of RecCo gross receivables.

As of February 23, 2021, outstanding borrowings under the receivables facility totaled approximately $ 596 million and were supported by approximately $ 774 million of RecCo gross receivables..

Repurchase Facility

In October 2020, TXU Energy and the other originators under the Receivables Facility entered into a $ 125 million repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer).

In July 2021, the Repurchase Facility was renewed until August 2021 and increased from $ 125 million to $ 150 million.

In August 2021, the Repurchase Facility was renewed until July 2022 and the facility size was decreased from $ 150 million to $ 125 million.

The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility.

3 unchanged sentences

Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the schedule termination of the Receivables Facility.

As of December 31, 2020, there were no borrowings under the Repurchase Facility.

In February 2021, the Company borrowed $ 125 million under the Repurchase Facility.

There were no outstanding borrowings under the Repurchase Facility at both December 31, 2021 and December 31, 2020.

LONG-TERM DEBT

10 unchanged sentences

5.000 % Senior Unsecured Notes, due July 31, 2027

4.375 % Senior Unsecured Notes, due May 15, 2029

Total Vistra Operations Senior Unsecured Notes 4,850 3,600

Vistra Senior Unsecured Notes:

5.875 % Senior Unsecured Notes, due June 1, 2023

8.000 % Senior Unsecured Notes, due January 15, 2025

8.125 % Senior Unsecured Notes, due January 30, 2026

Total Vistra Senior Unsecured Notes — 747

Forward Capacity Agreements 213 45

2 unchanged sentences

Total other long-term debt 311 126

Unamortized debt premiums, discounts and issuance costs (b) ( 68 ) ( 55 )

Unamortized debt premiums, discounts and issuance costs ( 73 ) ( 68 )

Total long-term debt including amounts due currently 10,731 9,330

2 unchanged sentences

(a) Obligation related to a corporate office space finance lease.

This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our consolidated balance sheets.

(b) Includes impact of recording debt assumed in the Merger at fair value.

This obligation will be funded by amounts held in an escrow account that is reflected in current assets in our consolidated balance sheets.

Vistra Operations Credit Facilities

At December 31, 2020, the Vistra Operations Credit Facilities consisted of up to $ 5.297 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $ 2.725 billion, including a $ 2.35 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $ 2.572 billion (Term Loan B-3 Facility).

As of December 31, 2021, the Vistra Operations Credit Facilities consisted of up to $ 5.268 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $ 2.725 billion, including a $ 2.35 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $ 2.543 billion (Term Loan B-3 Facility).

These amounts reflect the following transactions and amendments completed in 2021, 2020 and 2019:

• In March 2020, Vistra Operations repurchased $ 100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $ 93.875 and cancelled them.

• In March 2021, Vistra Operations borrowed $ 1.0 billion principal amount under the Term Loan A Facility.

In April 2021, Vistra Operations borrowed an additional $ 250 million principal amount under the Term Loan A Facility.

Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding under the Revolving Credit Facility.

Borrowings under the Term Loan A Facility were reported in short-term borrowings in our condensed consolidated balance sheet.

In May 2021, Vistra Operations used the proceeds from the issuance of the Vistra Operations 4.375 % senior unsecured notes due 2029 (described below), together with cash on hand, to repay the $ 1.250 billion borrowings under the Term Loan A Facility.

We recorded an extinguishment loss of $ 1 million on the transaction in the nine months ended September 30, 2021.

• In March 2020, Vistra Operations repurchased and cancelled $ 100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $ 93.875 .

We recorded an extinguishment gain of $ 6 million on the transaction in the year ended December 31, 2020.

9 unchanged sentences

Fees and expenses related to the amendments to the Vistra Operations Credit Facilities totaled $ 2 million for the year ended December 31, 2019, which were capitalized as a noncurrent asset.

• In June 2018, the Vistra Operations Credit Facilities were amended whereby we incurred $ 2.050 billion of borrowings under the new Term Loan B-3 Facility and obtained $ 1.640 billion of incremental Revolving Credit Facility commitments.

The letter of credit sub-facility was also increased by $ 1.585 billion.

The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023.

As discussed below, the proceeds from the Term Loan B-3 Facility were used to repay borrowings under the credit agreement that Vistra assumed from Dynegy in connection with the Merger.

Additionally, letter of credit term loans totaling $ 500 million (Term Loan C Facility) were repaid using $ 500 million of cash from collateral accounts used to backstop letters of credit.

Fees and expenses related to the amendment to the Vistra Operations Credit Facilities totaled $ 42 million in the year ended December 31, 2018, of which $ 23 million was recorded as interest expense and other charges on the consolidated statements of operations, $ 9 million was capitalized as a reduction in the carrying amount of the debt and $ 10 million was capitalized as a noncurrent asset.

During the year ended December 31, 2021, we borrowed $ 1.450 billion and repaid $ 1.450 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes.

6 unchanged sentences

Total Vistra Operations Credit Facilities $ 5,268 $ 2,543 $ 1,471 $ 1,254

(a) Revolving Credit Facility to be used for general corporate purposes.

(a) Revolving Credit Facility used for general corporate purposes.

The Facility includes a $ 2.35 billion letter of credit sub-facility.

1 unchanged sentence

Cash borrowings under the Revolving Credit Facility are reported in short-term borrowings in our consolidated balance sheets.

(b) Beginning in 2020, cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual amount equal to 1.00 % of the original principal amount with the balance paid at maturity.

(b) Cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual amount equal to 1.00 % of the original principal amount with the balance paid at maturity.

Amounts paid cannot be reborrowed.

In February 2018, June 2018 and November 2019, certain pricing terms for the Vistra Operations Credit Facilities were amended.

We accounted for these transactions as modifications of debt.

At December 31, 2020, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75 %, and there were no outstanding borrowings.

As of December 31, 2021, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75 %, and there were no outstanding borrowings.

Letters of credit issued under the Revolving Credit Facility bear interest of 1.75 %.

Amounts borrowed under the Term Loan B-3 Facility bears interest based on applicable LIBOR rates plus fixed spreads of 1.75 %.

At December 31, 2020, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 1.90 % under the Term Loan B-3 Facility.

As of December 31, 2021, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 1.86 % under the Term Loan B-3 Facility.

The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the available Revolving Credit Facility.

5 unchanged sentences

Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $ 300 million) exceed 30 % of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 4.25 to 1.00.

Although the period ended December 31, 2020 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such time.

As of December 31, 2021, we were in compliance with this financial covenant.

Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

14 unchanged sentences

The remaining existing swaps continue to hedge our exposure on $ 2.30 billion of debt through July 2026.

Commodity-Linked Revolving Credit Facility

On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent.

The Credit Agreement provides for a $ 1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility).

Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the facility limit nor be less than zero.

Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base.

Secured Letter of Credit Facilities

In August and September 2020, Vistra entered into four uncommitted 364-day standby letter of credit facilities (Secured LOC Facilities) that are each secured by a first lien on all of Vista Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities).

At December 31, 2020, $ 303 million of letters of credit were outstanding under the Secured LOC Facilities.

In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that are each secured by a first lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities).

The Secured LOC Facilities are used for general corporate purposes.

In October 2021, Vistra entered into an additional Secured LOC Facility which will also be used for general corporate purposes.

As of December 31, 2021, $ 406 million of letters of credit were outstanding under the Secured LOC Facilities.

Alternate Letter of Credit Facilities

Two alternate letter of credit facilities (each, an Alternate LOC Facility) became effective in the year ended December 31, 2019.

Two alternate letter of credit facilities (each, an Alternate LOC Facility) became effective in the years ended December 31, 2018 and 2019, respectively.

One Alternate LOC Facility with an aggregate facility limit of $ 250 million matured in December 2020.

The remaining Alternate LOC Facility with an aggregate facility limit of $ 250 million matures in December 2021.

At December 31, 2020, $ 245 million of letters of credit were outstanding under this Alternate LOC Facility.

The remaining Alternate LOC Facility with an aggregate facility limit of $ 250 million matured in December 2021.

Vistra Operations Senior Secured Notes

23 unchanged sentences

Vistra Operations Senior Unsecured Notes

In 2018 and 2019, Vistra Operations issued and sold $ 3.6 billion aggregate principal amount of senior unsecured notes in offerings (the August 2018 Senior Unsecured Notes Offering, the February 2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offerings) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the following:

In 2019 and 2021, Vistra Operations issued and sold $3.9 billion aggregate principal amount of senior unsecured notes in offerings (the February 2019 Senior Unsecured Notes Offering, June 2019 Senior Unsecured Notes Offerings and the May 2021 Senior Unsecured Offerings) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the following:

Senior Unsecured Notes Maturity Year Interest Terms

(Due Semiannually in Arrears) August 2018 Senior Unsecured Notes Offering (a) February 2019 Senior Unsecured Notes Offering (b) June 2019

(Due Semiannually in Arrears) February 2019 Senior Unsecured Notes Offering (a) June 2019

Senior Unsecured Notes Offering (b) May 2021

Senior Unsecured Notes Offering (c)

5.625 % Senior Unsecured Notes

2026 March 1 and September 1 $ 1,000 $ — $ —

5.625 % Senior Unsecured Notes

2027 February 15 and August 15 1,300 — —

1 unchanged sentence

2027 January 31 and July 31 — 1,300 —

4.375 % Senior Unsecured Notes

2029 May 1 and November 1 — — 1,250

Total $ 1,300 $ 1,300 $ 1,250

1 unchanged sentence

Debt issuance and other fees (d) $ 16 $ 13 $ 15

(a) The 5.500 % senior unsecured notes due 2026 (the August 2018 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Citigroup Global Markets Inc., as representative of the several initial purchasers.

Net proceeds, together with cash on hand and cash received from the funding of the Receivables Facility (see Note 10), were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the 2018 Tender Offers (defined below).

(b) The 5.625 % senior unsecured notes due 2027 (the February 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P.

(a) The 5.625 % senior unsecured notes due 2027 (the February 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P.

Morgan Securities LLC., as representative of the several initial purchasers.

Net proceeds, together with cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with (i) the February 2019 Tender Offer, (defined below) and (ii) the redemption of approximately $ 35 million aggregate principal amount of our 7.375 % senior unsecured notes due 2022 ( 7.375 % senior notes) and approximately $ 25 million aggregate principal amount of our outstanding 8.034 % senior unsecured notes due 2024 ( 8.034 % senior notes).

(c) The 5.000 % senior unsecured notes due 2027 (the June 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Goldman Sachs & Co.

(b) The 5.000 % senior unsecured notes due 2027 (the June 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Goldman Sachs & Co.

LLC, as representative of the several initial purchasers.

1 unchanged sentence

We recorded an extinguishment gain of $ 2 million on the redemptions in the year ended December 31, 2019

(c) The 4.375 % senior unsecured notes due 2029 (the May 2021 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P.

Morgan Securities LLC., as representative of the several initial purchasers.

Net proceeds.

together with cash on hand, were used to pay all amounts outstanding under the Term Loan A Facility and to pay fees and expenses of $ 15 million related to the offering.

(d) Capitalized as a reduction in the carrying amount of the debt.

The indentures governing the June 2019 Senior Unsecured Notes, the February 2019 Senior Unsecured Notes and the August 2018 Senior Unsecured Notes (collectively, as each may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes.

Since 2018, Vistra Operations has issued and sold $ 4.850 billion aggregate principal amount of senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

The indentures governing the May 2021 Senior Unsecured Notes, the June 2019 Senior Unsecured Notes, the February 2019 Senior Unsecured Notes and the 5.500 % senior unsecured notes due 2026 (collectively, as each may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes.

The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

Debt Repurchase Program

In November 2018, our board of directors (the Board) authorized a bond repurchase program under which up to $ 200 million principal amount of outstanding Vistra Senior Unsecured Notes could be repurchased.

Through June 30, 2019, $ 119 million principal amount of Vistra Senior Unsecured Notes had been repurchased.

In July 2019, the Board authorized up to $ 1.0 billion to repay or repurchase any outstanding debt of the Company (or its subsidiaries), with that authority superseding the remaining availability under the $ 200 million bond repurchase program.

Through April 2020, $ 684 million amount of debt had been repurchased under the $ 1.0 billion July 2019 authorization, including the repurchase of $ 100 million principal amount of Term Loan B-3 Facility borrowings discussed above and the redemption of $ 81 million aggregate principal amount outstanding of 8.000 % senior unsecured notes due 2025 ( 8.000 % senior notes) discussed below.

In July 2019, the Board authorized up to $ 1.0 billion to repay or repurchase any outstanding debt of the Company (or its subsidiaries).

Through April 2020, $ 684 million of debt had been repurchased under the $ 1.0 billion July 2019 authorization, including the repurchase of $ 100 million principal amount of Term Loan B-3 Facility borrowings discussed above and the redemption of $ 81 million aggregate principal amount outstanding of 8.000 % senior unsecured notes due 2025 ( 8.000 % senior notes) discussed below.

In April 2020, the Board authorized up to $ 1.0 billion to repay or repurchase additional outstanding debt, with this new authority superseding and replacing the $ 316 million of availability under the previously authorized $ 1.0 billion debt repurchase program.

3 unchanged sentences

In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.

Following the redemption, repurchase and tender offer transactions below, Vistra had no outstanding senior notes at the Parent level.

Vistra Senior Unsecured Notes Maturity Year 2018 Redemptions/Repurchases (a) August

2018 Tender Offer (b) February 2019 Tender Offer (c) June

2019 Tender Offer (d) 2019 Redemptions (e) 2020 Redemptions (f)

The following amounts reflect redemption, repurchase and tender offer transactions completed in 2019 and 2020.

Vistra had no outstanding senior notes at the Parent level as of December 31, 2021 and 2020.

Vistra Senior Unsecured Notes Maturity Year February 2019 Tender Offer (a) June

6.750 %Senior Unsecured Notes

14 unchanged sentences

Extinguishment gain/(loss) $ 7 $ 7 $ 11 $ 11

(a) In May 2018, $ 850 million of outstanding 6.75 % senior unsecured notes due 2019 were redeemed at a redemption price of 101.688 % of the aggregate principal amount, plus accrued and unpaid interest up to but not including the date of redemption.

Fees and expenses related to the redemption totaled $ 14 million in the year ended December 31, 2018 and were recorded as interest expense and other charges on the consolidated statements of operations.

In addition, Vistra repurchased $ 119 million of Vistra Senior Unsecured Notes under the bond repurchase program described above.

(b) In August 2018, Vistra used the net proceeds from the August 2018 Senior Unsecured Notes Offering, proceeds from the Receivables Facility (see Note 10) and cash on hand to fund cash tender offers (the 2018 Tender Offers) to purchase for cash $ 1.542 billion aggregate principal amount of Vistra Senior Unsecured Notes.

(c) In February 2019, Vistra used the net proceeds from the February 2019 Senior Unsecured Notes Offering to fund a cash tender offer (the February 2019 Tender Offer) to purchase for cash $ 1.193 billion aggregate principal amount of 7.375 % senior notes.

(d) In June 2019, Vistra used the net proceeds from the June 2019 Notes Offering to fund a cash tender offer (the June 2019 Tender Offer) to purchase for cash $ 173 million of 7.375 % senior notes and $ 672 million of 7.625 % senior notes.

(a) In February 2019, Vistra used the net proceeds from the February 2019 Senior Unsecured Notes Offering to fund a cash tender offer (the February 2019 Tender Offer) to purchase for cash $ 1.193 billion aggregate principal amount of 7.375 % senior notes.

(b) In June 2019, Vistra used the net proceeds from the June 2019 Notes Offering to fund a cash tender offer (the June 2019 Tender Offer) to purchase for cash $ 173 million of 7.375 % senior notes and $ 672 million of 7.625 % senior notes.

In July 2019, Vistra accepted and settled an additional approximately $ 1 million aggregate principal amount of outstanding 7.625 % senior notes that were tendered after the early tender date of the June 2019 Tender Offer.

(e) In November 2019, Vistra redeemed $ 387 million aggregate principal amount outstanding of 7.625 % senior notes at a redemption price equal to 103.8 % of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption (the 2019 Redemption).

(c) In November 2019, Vistra redeemed $ 387 million aggregate principal amount outstanding of 7.625 % senior notes at a redemption price equal to 103.8 % of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption (the 2019 Redemption).

Vistra redeemed $ 341 million, $ 87 million and $ 25 million aggregate principal amount of 7.375 % senior notes, 7.625 % senior notes and 8.034 % senior notes, respectively, using proceeds from the February 2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offerings discussed above.

(f) In January 2020, June 2020 and July 2020, Vistra redeemed aggregate principal amounts of $ 81 million of 8.000 % senior notes, $ 500 million of 5.875 % senior notes and $ 166 million of 8.125 % senior notes, respectively, at redemption prices of 104 %, 100.979 % and 104.063 %, respectively, of the aggregate principal amounts thereof, plus accrued and unpaid interest to, but excluding, the dates of redemption (the 2020 Redemptions, and together with the 2019 Redemption, the Redemptions) .

(d) In January 2020, June 2020 and July 2020, Vistra redeemed aggregate principal amounts of $ 81 million of 8.000 % senior notes, $ 500 million of 5.875 % senior notes and $ 166 million of 8.125 % senior notes, respectively, at redemption prices of 104 %, 100.979 % and 104.063 %, respectively, of the aggregate principal amounts thereof, plus accrued and unpaid interest to, but excluding, the dates of redemption (the 2020 Redemptions, and together with the 2019 Redemption, the Redemptions).

February 2019 Consent Solicitation — In connection with the February 2019 Tender Offer, Vistra also commenced solicitation of consents from holders of the 7.375 % senior notes.

Vistra received the requisite consents from the holders of the 7.375 % senior notes and amended the indenture governing these senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default.

August 2018 Consent Solicitations — In connection with the 2018 Tender Offers, Vistra also commenced solicitations of consents from holders of the 7.375 % senior notes, the 7.625 % senior notes, the 8.034 % senior notes, the 8.000 % senior notes and the 8.125 % senior notes to amend certain provisions of the applicable indentures governing each series of senior notes and the registration rights agreement with respect to the 8.125 % senior notes.

Vistra received the requisite consents from the holders of the 8.034 % senior notes, the 8.000 % senior notes and the 8.125 % senior notes (collectively, the Consent Senior Notes) and amended (a) the indentures governing each series of the applicable senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default and (b) the registration rights agreement with respect to the 8.125 % senior notes to remove, among other things, the requirement that Vistra commence an exchange offer to issue registered securities in exchange for the existing, nonregistered notes.

Other Long-Term Debt

5 unchanged sentences

On the maturity date, the Company paid all amounts due under the Amortizing Notes Indenture and the Amortizing Notes Indenture ceased to be of further force and effect.

Forward Capacity Agreements — On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Forward Capacity Agreements).

The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2020-2021 in the amount of $ 45 million.

Forward Capacity Agreements — In March 2021, the Company sold a portion of the PJM capacity that cleared for Planning Years 2021-2022 to a financial institution (2021-2022 Forward Capacity Agreement).

The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2021-2022 in the amount of approximately $ 515 million.

We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years.

As a result, this transaction is accounted for as long-term debt with an implied interest rate of 1.14 %.

Equipment Financing Agreements — On the Merger Date, the Company assumed Dynegy's Equipment Financing Agreements.

Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units.

As a result, this transaction is accounted for as a debt issuance with an implied interest rate of approximately 4.25 %.

On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Legacy Forward Capacity Agreements, and, together with the 2021-2022 Forward Capacity Agreement, the Forward Capacity Agreements).

In May 2021, the final capacity payment from PJM during the Planning Years 2020-2021 was paid, and the terms of the Legacy Forward Capacity were fulfilled.

Equipment Financing Agreements — On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units.

We financed these parts and equipment under agreements with maturities ranging from 2021 to 2026.

7 unchanged sentences

In November 2019, borrowings of $ 8 million under the Connecticut Department of Economic and Community Development term loans were repaid using cash on hand.

Vistra (legacy Dynegy) Credit Agreement — On the Merger Date, Vistra assumed the obligations under Dynegy's $ 3.563 billion credit agreement consisting of a $ 2.018 billion senior secured term loan facility due 2024 and a $ 1.545 billion senior secured revolving credit facility.

As of the Merger Date, there were no cash borrowings and $ 656 million of letters of credit outstanding under the senior secured revolving credit facility.

On April 23, 2018, $ 70 million of the senior secured revolving credit facility matured.

In June 2018, the $ 2.018 billion senior secured term loan facility due 2024 was repaid using proceeds from the Term Loan B-3 Facility.

In addition, all letters of credit outstanding under the senior secured revolving credit facility were replaced with letters of credit under the amended Vistra Operations Credit Facilities discussed above, and the revolving credit facility assumed from Dynegy in connection with the Merger was paid off in full and terminated.

Long-term debt maturities at December 31, 2021 are as follows:

9 unchanged sentences

Year Ended December 31,

2021 2020 2019

Operating lease cost $ 11 $ 14 $ 14

27 unchanged sentences

Year Ended December 31,

2021 2020 2019

Cash paid for amounts included in the measurement of lease liabilities:

24 unchanged sentences

Present value of lease liabilities $ 43 $ 243 $ 286

As of December 31, 2020, we have approximately $ 7 million of operating leases that have not yet commenced.

COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2020, we had contractual commitments under long-term service and maintenance contracts, energy-related contracts, leases and other agreements as follows.

Long-Term Service and Maintenance Contracts Coal purchase and

transportation agreements Pipeline transportation and storage reservation fees Nuclear

Fuel Contracts Other

As of December 31, 2021, we had minimum contractual commitments under long-term service and maintenance contracts, energy-related contracts, leases and other agreements as follows.

Long-Term Service and Maintenance Contracts (a) Coal transportation agreements Pipeline transportation and storage reservation fees Water

2022 $ 202 $ 104 $ 86 $ 9

5 unchanged sentences

Total $ 3,239 $ 228 $ 330 $ 103

The table above excludes TRA and pension and OPEB plan obligations due to the uncertainty in the timing of those payments.

Expenditures under our coal purchase and coal transportation agreements totaled $ 845 million, $ 1.092 billion, and $ 955 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Rent reported as operating costs and SG&A expenses totaled $ 111 million, $ 89 million, and $ 74 million for the years ended December 31, 2020, 2019 and 2018, respectively.

(a) Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company.

In addition to the commitments detailed above, we have nuclear fuel contracts with early termination penalties.

As of December 31, 2021, termination costs of $ 54 million would be incurred if we terminated those contracts.

Expenditures under our coal purchase and coal transportation agreements totaled $ 850 million, $ 845 million, and $ 1.092 billion for the years ended December 31, 2021, 2020 and 2019, respectively.

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.

As of December 31, 2020, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees in the near term.

Material guarantees are discussed below.

Letters of Credit

At December 31, 2020, we had outstanding letters of credit totaling $ 1.286 billion as follows:

• $ 878 million to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;

As of December 31, 2021, we had outstanding letters of credit totaling $ 1.877 billion as follows:

• $ 1.558 billion to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;

• $ 157 million to support battery and solar development projects;

2 unchanged sentences

• $ 61 million for other credit support requirements.

At December 31, 2020, we had outstanding surety bonds totaling $ 100 million to support performance under various contracts and legal obligations in the normal course of business.

As of December 31, 2021, we had outstanding surety bonds totaling $ 561 million to support performance under various contracts and legal obligations in the normal course of business.

Litigation and Regulatory Proceedings

11 unchanged sentences

The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes.

We remain as defendants in two consolidated putative class actions (Wisconsin) and one individual action (Kansas) both pending in federal court in those states.

The Kansas action is currently on appeal in the U.S.

Court of Appeals for the Tenth Circuit.

In December 2021, we settled an individual action with Reorganized FLI, Inc., as successor to Farmland Industries, Inc., that was pending in Kansas federal court, and that case has now been dismissed.

We remain as a defendant in one other action, which is a consolidated putative class action lawsuit pending in federal court in Wisconsin.

Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads.

Settlement discussions required under the dispute resolution process have been unsuccessful.

In March 2018, BNSF Railway Company (BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration and an arbitration hearing is currently scheduled for March 2021.

In March 2018, BNSF Railway Company (BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration.

In March 2021, the parties entered into a confidential settlement to resolve this matter and the Coffeen matter discussed below.

In connection with that settlement, BNSF and NS dismissed with prejudice their arbitration disputes for Wood River and Coffeen and these matters are fully resolved.

Coffeen and Duck Creek Rail Disputes — In April 2020, IPH, LLC (IPH) received notification that BNSF and NS were initiating dispute resolution related to IPH's suspension of its Coffeen Rail Transportation Agreement with the railroads, and Illinois Power Resources Generating, LLC (IPRG), received notification that BNSF was initiating dispute resolution related to IPRG's suspension of its Duck Creek Rail Transportation Agreement with BNSF.

1 unchanged sentence

In addition, IPH and IPRG asserted that the MPS rule's retirement requirement also qualified as a force majeure event under the agreements excusing performance.

ME2C Patent Dispute — In July 2019, Midwest Energy Emissions Corporation and MES Inc.

(collectively, the plaintiffs) filed a patent infringement complaint in federal court in Delaware against numerous parties, including Vistra and some of its subsidiaries (collectively, the Vistra defendants), and its amended complaint in July 2020.

The amended complaint alleges that the Vistra defendants infringed five patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fueled plants.

The amended complaint seeks injunctive relief and unspecified damages.

In July 2020, the plaintiffs and the Vistra defendants entered into an agreement resolving all the claims alleged against the Vistra defendants in the complaint.

The court signed its stipulation and order of dismissal in July 2020, dismissing the Vistra defendants from the lawsuit.

In March 2021, we entered into a confidential settlement agreement with BNSF to resolve the Duck Creek matter and a separate confidential settlement agreement with BNSF and NS to resolve the Coffeen and Wood River matter discussed above.

BNSF has dismissed with prejudice the Duck Creek arbitration dispute and this matter is now fully resolved.

The settlement of these rail disputes did not have a material impact on our financial statements.

Winter Storm Uri Legal Proceedings

Repricing Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of wholesale power prices during load-shedding events.

We filed our opening brief in June 2021, and response briefs were filed in September 2021.

In our brief, we argue that the prior PUCT rushed to adopt a rule that dramatically raised the price of electricity in ERCOT, but in doing so failed to follow any of the rulemaking procedures required for the PUCT to undertake an emergency rulemaking, and we have asked the court to vacate this rule.

Other parties also filed briefs in support of our challenge to the PUCT's orders.

In addition, we have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri.

Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with the Third Court of Appeals that the PUCT has not prejudged or made a final decision on whether to reprice and that we and other parties may continue disputing the pricing through the ERCOT process.

Koch Disputes — In March 2021, we filed a lawsuit in Texas state court against Odessa-Ector Power Partners, L.P., Koch Resources, LLC, Koch AG & Energy Solutions, LLC, and Koch Energy Services, LLC (Koch) seeking equitable relief in which we contested the amount of the February 2021 earnout payment under the terms of the 2017 asset purchase agreement (APA) with Koch.

Koch subsequently filed its own related lawsuit in Delaware Chancery Court, and the Delaware Chancery Court ruled that all claims related to the APA dispute (including our equitable claims) would proceed in Delaware.

We contested Koch's demand for $ 286 million for the February 2021 earnout payment as an unjust windfall and inconsistent with the parties' intent when they entered into the APA in 2017.

We recorded a $ 286 million liability in other noncurrent liabilities and deferred credits in our consolidated balance sheets.

In March 2021, we also filed a lawsuit in New York state court against Koch for breach of contract and ineffective notice of force majeure related to Koch's failure to deliver contracted-for quantities of gas during Winter Strom Uri, which Koch removed to federal court.

In November 2021, the disputes we had with Koch were resolved to the parties' mutual satisfaction and all the lawsuits have been dismissed.

The matter was resolved within the amount that was reserved and will be paid in the second quarter of 2022.

Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, the Texas Attorney General, the FERC and the NRC initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues.

We responded to all those investigatory requests.

In addition, a number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT.

We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge.

In June 2021, the MDL panel granted the request to consolidate all these cases into a MDL for pretrial proceedings.

In addition, in January 2022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred insurance companies against ERCOT, Vistra and several other defendants.

The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri.

We believe we have strong defenses to this lawsuit and the other tort lawsuits and intend to defend against these cases vigorously.

Climate Change

1 unchanged sentence

Several of the EPA agency actions discussed below are now subject to this review.

Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals to reduce nationwide CO 2 emissions.

Various parties filed petitions for review in the U.S.

Greenhouse Gas Emissions (GHG)

In July 2019, the EPA finalized a rule to that repealed the Clean Power Plan (CPP) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule.

The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units.

In response to challenges brought by Environmental groups and certain states, the U.S.

Court of Appeals for the District of Columbia Circuit (D.C.

Circuit Court).

In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's new rule that replaces the Clean Power Plan, the Affordable Clean Energy rule, discussed below.

In September 2019, the D.C.

Circuit Court granted petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.

In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule.

The ACE rule develops emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units.

The ACE rule set a deadline of July 2022 for states to submit their plans for regulating GHG emissions from existing facilities.

States where we operate coal plants (Texas, Illinois and Ohio) have begun the development of their state plans to comply with the rule.

Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power Plan in the D.C.

Circuit Court, and the D.C.

Circuit Court heard argument on those issues in October 2020.

In January 2021, the D.C.

Circuit Court vacated the ACE rule and remanded the rule to the EPA for further action.

In its decision, the D.C.

Circuit Court concluded that the EPA's basis for repealing the Clean Power Plan and adopting the ACE rule was not supported by the Clean Air Act.

Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units.

Vistra submitted comments on that proposed rulemaking in March 2019.

In January 2021, the EPA, just prior to the transition to the Biden administration, issued a final rule setting forth a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units.

The final rule excludes sectors from future regulation where GHG emissions make up less than three percent of U.S.

GHG emissions.

The final rule did not set any specific emission limits for new, modified, or reconstructed electric utility generating units.

Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action.

In October 2021, the U.S.

Supreme Court granted four petitions for certiorari of the D.C.

Circuit Court's decision and consolidated the cases for review.

The case is now fully briefed and scheduled for oral argument in February 2022.

Additionally, in January 2021, the EPA, just prior to the transition to the Biden administration, issued a final rule setting forth a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units.

In April 2021, the D.C.

Circuit Court granted the EPA's unopposed motion for voluntary vacatur and remand of the GHG significant contribution rule.

The ACE rule and the rule on significant contribution are subject to the Environment Executive Order discussed above.

2 unchanged sentences

For SO 2 , the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program.

The program includes 39 generating units (including our Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants).

The program includes 39 generating units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants).

The compliance obligations in the program started on January 1, 2019.

The retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply with this BART rule for SO 2 .

For NO X , the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas's SIP that determines that no electricity generation units are subject to BART for particulate matter.

Various parties filed a petition challenging the rule in the U.S.

Court of Appeals for the Fifth Circuit (Fifth Circuit Court) as well as a petition for reconsideration filed with the EPA.

Luminant intervened on behalf of the EPA in the Fifth Circuit Court action.

In March 2018, the Fifth Circuit Court abated its proceedings pending conclusion of the EPA's reconsideration process.

In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019.

In October 2020, environmental groups petitioned for review of this rule in both the D.C.

Circuit Court and the Fifth Circuit Court.

Briefing is underway on the proper venue for any challenge to the final rule.

As finalized, we expect that we will be able to comply with the rule.

The BART rule is subject to the Environment Executive Order discussed above.

Affirmative Defenses During Malfunctions

In May 2015, the EPA finalized a rule requiring 36 states, including Texas, Illinois and Ohio, to remove or replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during upset events and unplanned maintenance and startup and shutdown events, referred to as the SIP Call.

Various parties (including Luminant, the State of Texas and the State of Ohio) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C.

Circuit Court.

In April 2017, the D.C.

Circuit Court ordered the case to be held in abeyance.

In April 2019, the EPA Region 6 proposed a rule to withdraw the SIP Call with respect to the Texas affirmative defense provisions.

We submitted comments on that proposed rulemaking in June 2019.

In February 2020, the EPA issued the final rule withdrawing the Texas SIP Call.

In April 2020, a group of environmental petitioners, including the Sierra Club, filed a petition in the D.C.

Circuit Court challenging the EPA's action with respect to Texas.

Briefing is currently underway in the challenge to the EPA's action with respect to Texas.

In October 2020, the EPA issued new guidance on the inclusion of startup, shutdown and malfunction (SSM) provisions in SIPs, which is intended to supersede the policy in the multi-state SIP Call.

The guidance provides that the SIPs may contain provisions for SSM events if certain conditions are met.

The EPA SSM guidance is subject to the Environment Executive Order discussed above.

Illinois Multi-Pollutant Standards (MPS)

In August 2019, changes proposed by the Illinois Pollution Control Board to the MPS rule, which places NO X , SO 2 and mercury emissions limits on our coal plants located in MISO went into effect.

Under the revised MPS rule, our allowable SO 2 and NO X emissions from the MISO fleet are 48 % and 42 % lower, respectively, than prior to the rule changes.

The revised MPS rule requires the continuous operation of existing selective catalytic reduction (SCR) control systems during the ozone season, requires SCR-controlled units to meet an ozone season NO X emission rate limit, and set an additional, site-specific annual SO 2 limit for our Joppa Power Station.

Additionally, in 2019, the Company retired its Havana, Hennepin, Coffeen and Duck Creek plants in order to comply with the MPS rule's requirement to retire at least 2,000 MW of our generation in MISO.

See Note 4 for information regarding the retirement of these four plants.

Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C.

Circuit Court, where we have intervened in support of the EPA.

We are in compliance with the rule, and the retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply.

The BART rule is subject to the Environment Executive Order discussed above, and the EPA has stated it is starting a proceeding for reconsideration of the BART rule.

The challenges in the D.C.

Circuit Court have been held in abeyance pending the EPA's action on reconsideration.

SO 2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants.

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now-retired Big Brown and Monticello plants.

The final designations require Texas to develop nonattainment plans for these areas.

In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court.

In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the U.S.

Court of Appeals for the Fifth Circuit (Fifth Circuit Court).

Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule.

In December 2017, the TCEQ submitted a petition for reconsideration to the EPA.

In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would revise its previous nonattainment designations and each area at issue would be designated unclassifiable.

In September 2019, we submitted comments in support of the proposed Error Correction Rule.

In April 2020, the Sierra Club filed suit to compel the EPA to issue a Finding of Failure to submit an attainment plan with respect to the three areas in Texas.

In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable.

In August 2020, the EPA issued a Finding of Failure for Texas to submit an attainment plan.

In September 2020, the EPA proposed a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, which, if finalized, would redesignate those areas as attainment based on monitoring data supporting an attainment designation.

We expect the TCEQ to develop a SIP for Texas for submittal to the EPA in 2021.

In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation.

In June 2021, the EPA published two notices;

one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations.

We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, with the matter likely being fully briefed by March 2022.

In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO 2 emissions from the plant.

The proposed agreed order associated with the SIP proposal reduces emission limits as of January 2022.

Emission reductions required are those necessary to demonstrate attainment with the NAAQS.

The TCEQ's SIP action was finalized in February 2022 and will be submitted to the EPA for review and approval.

Effluent Limitation Guidelines (ELGs)

2 unchanged sentences

In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines.

In August 2017, the EPA announced that its reconsideration of the ELG rule would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rule for the application of effluent limitations for FGD and bottom ash wastewaters from November 1, 2018 to November 1, 2020.

Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to effluent limitations.

Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to those effluent limitations.

The remainder of the case proceeded, and in April 2019 the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate.

In November 2019, the EPA issued a proposal that would extend the compliance deadline for FGD wastewater to no later than December 31, 2025 and maintains the December 31, 2023 compliance date for bottom ash transport water.

The proposal also creates new sub-categories of facilities with more flexible FGD compliance options, including a retirement exemption to 2028 and a low utilization boiler exemption.

The proposed rule also modified some of the FGD final effluent limitations.

We filed comments on the proposal in January 2020.

The EPA published the final rule in October 2020.

The final rule extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency.

The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency.

Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met.

Notification to the state agency on the retirement exemption is due by October 2021.

In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020.

The final rule is subject to the Environment Executive Order discussed above.

In July 2021, the EPA announced its intent to revise the ELG rule and moved to hold the 2020 ELG revision litigation in abeyance pending the EPA's completion of its reconsideration rulemaking.

Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021.

Coal Combustion Residuals (CCR)/Groundwater

In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of the CCR rule that the agency issued in 2015.

Among other changes, the 2018 revisions extended closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements.

Also, in August 2018, the D.C.

In August 2018, the D.C.

Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments.

In December 2019, the EPA issued a proposed rule containing a revised closure deadline for unlined CCR impoundments and new procedures for seeking extensions of that revised closure deadline.

We filed comments on the proposal in January 2020.

In August 2020, the EPA issued a rule finalizing the December 2019 proposal, establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments.

In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments.

The final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue).

4 unchanged sentences

In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake.

In October 2020, the EPA published an advanced notice of proposed rulemaking requesting information to inform the EPA in the development of a rule to address legacy impoundments that existed prior to the 2015 CCR regulation as required by the August 2018 D.C.

Circuit Court decision.

We filed comments on this proposal in February 2021.

The rules on revised closure deadlines and alternative liner demonstrations are subject to the Environment Executive Order discussed above.

In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following announcement that Zimmer will close by May 31, 2022.

In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet made a final determination on any of those applications.

MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments.

1 unchanged sentence

however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments.

We are working towards implementation of those closure plans.

At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the aforementioned D.C.

We have completed closure activities at those ponds at our Baldwin facility.

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C.

Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments ( i.e.

1 unchanged sentence

In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options.

In May 2018, Prairie Rivers Network filed a citizen suit in federal court in Illinois against DMG, alleging violations of the Clean Water Act for alleged unauthorized discharges.

In May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against DMG, alleging violations of the Clean Water Act for alleged unauthorized discharges.

In August 2018, we filed a motion to dismiss the lawsuit.

In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor.

Plaintiffs have appealed the judgment to the U.S.

Court of Appeals for the Seventh Circuit and argument was heard in November 2020.

In June 2021, the U.S.

Court of Appeals for the Seventh Circuit affirmed the district court's dismissal of the lawsuit, but stated that PRN may refile.

In April 2019, PRN also filed a complaint against DMG before the IPCB, alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992.

This matter is in the very early stages.

We answered that complaint in July 2021, and this matter remains in the very early stages.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments.

We are addressing these CCR surface impoundments in accordance with the federal CCR rule.

In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility and that notice has since been referred to the Illinois Attorney General.

In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the Coffeen, Edwards and Joppa generation facilities are causing exceedances of the applicable groundwater standards.

In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General.

In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered.

Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter.

Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal.

In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments.

These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note 21).

In July 2019, coal ash disposal and storage legislation in Illinois was enacted.

1 unchanged sentence

The law tasks the IEPA and the IPCB to set up a series of guidelines, rules and permit requirements for closure of ash ponds.

In March 2020, the IEPA issued its proposed rule, and we expect the rulemaking process should be completed by early 2021.

Under the proposed rule, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site.

The proposed rule does not mandate closure by removal at any site.

Public hearings for the proposed rule were held in August 2020 and September 2020.

We expect that the rule will be finalized by March 2021.

Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site.

The rule does not mandate closure by removal at any site.

In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule.

We filed our opening brief in October 2021.

Other parties have also filed appeals of certain provisions of the final rule.

In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022.

For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows.

Until the revisions to the Illinois coal ash rulemaking are finalized and we undertake further site specific evaluations required by each program we will not know the full range of costs of groundwater remediation, if any, that ultimately may be required under those rules.

However, the currently anticipated CCR surface impoundment and landfill closure costs, as contained in our AROs, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.

The Illinois coal ash rule was finalized in April 2021 and does not require removal.

However, the rule will require us to undertake further site specific evaluations required by each program.

We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been submitted and approved by the IEPA.

However, the currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabilities, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.

MISO 2015-2016 Planning Resource Auction

18 unchanged sentences

Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020.

The appeal remains pending.

In August 2021, the D.C.

Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that FERC failed to meet its obligation to ensure just and reasonable rates because it did not review the prices resulting from the auction before those prices went into effect and that FERC was arbitrary and capricious in failing to adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation.

Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that FERC's decision that the auction results were just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case back to FERC for further proceedings on that issue.

On February 4, 2022 the Illinois Attorney General and Public Citizen, Inc.

filed a motion at FERC requesting that FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery.

We intend to vigorously defend our position, including by filing a response to the motion.

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

Labor Contracts

We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements.

The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal- and nuclear-fueled generation operations and some of our natural gas-fueled generation operations expire on various dates between May 2021 and November 2023, but remain effective thereafter unless and until terminated by either party.

We are also presently negotiating the terms of first contracts at two of our natural gas-fueled generation facilities.

While we cannot predict the outcome of labor contract negotiations, we do not expect any negotiated terms in our new collective bargaining agreements or changes in our existing agreements to have a material adverse effect on our results of operations, liquidity or financial condition.

The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, natural gas- and nuclear-fueled generation operations, as well as some battery operations, expire on various dates between March 2022 and May 2024, but remain effective thereafter unless and until terminated by either party.

While we cannot predict the outcome of labor contract negotiations, we do not expect any changes in our existing agreements to have a material adverse effect on our results of operations, liquidity or financial condition.

Nuclear Insurance

21 unchanged sentences

The coverage amounts applicable to each unit will be reduced to 80 % if both units are out of service at the same time as a result of the same accident.

Equity Issuances and Repurchases

Common Stock Issuances and Repurchases

Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2021, 2020 and 2019 are reflected in the table below.

6 unchanged sentences

Balance at December 31, 2019 528,741,335 ( 41,043,224 ) 487,698,111

Shares issued (a) (c) 2,716,349 18,773,958 21,490,307

Shares issued (a) 1,611,462 — 1,611,462

Shares retired ( 3,685 ) — ( 3,685 )

Shares repurchased — ( 27,001,399 ) ( 27,001,399 )

Balance at December 31, 2020 530,349,112 ( 41,043,224 ) 489,305,888

1 unchanged sentence

Shares retired ( 3,397 ) — ( 3,397 )

Shares repurchased (c) — ( 27,988,518 ) ( 27,988,518 )

Balance at December 31, 2021 532,929,476 ( 69,031,742 ) 463,897,734

(a) Shares issued includes share awards granted to nonemployee directors.

(b) The year ended December 31, 2018 includes 94,409,573 shares issued in connection with the Merger (see Note 2).

(c) The year ended December 31, 2019 includes 18,773,958 treasury shares issued in connection with the settlement of all outstanding TEUs as discussed below.

(b) The year ended December 31, 2019 includes 18,773,958 treasury shares issued in connection with the settlement of all outstanding TEUs as discussed below.

(c) Shares repurchased in the year ended December 31, 2021 include 5,174,863 of unsettled shares as of December 31, 2021.

Share Repurchase Programs

In September 2020, we announced that the Board authorized a new share repurchase program (Share Repurchase Program) under which up to $ 1.5 billion of our outstanding shares of common stock may be repurchased.

The Share Repurchase Program was effective January 1, 2021, at which time the Prior Share Repurchase Plan (described below) and all authorized amounts remaining thereunder terminated as of such date.

In October 2021, we announced that the Board has authorized a new 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.

We intend to use the net proceeds from the Offering (described below) to repurchase shares of our outstanding common stock.

In the three months ended December 31, 2021, 19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $ 409 million at an average price of $ 21.16 per share of common stock.

As of December 31, 2021, approximately $ 1.591 billion was available for additional repurchases under the Share Repurchase Program.

From January 1, 2022 through February 22, 2022, 16,059,290 of our common stock had been repurchased under the Share Repurchase Program for $ 355 million at an average price per share of common stock of $ 22.07 , and at February 22, 2022, $ 1.236 billion was available for repurchase under the Share Repurchase Program.

We expect to complete repurchases under the Share Repurchase Program by the end of 2022.

Under the Share Repurchase Program, shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act, or by other means in accordance with federal securities laws.

The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements.

In September 2020, we announced that the Board authorized a share repurchase program (2020 Share Repurchase Program) under which up to $ 1.5 billion of our outstanding shares of common stock may be repurchased.

The 2020 Share Repurchase Program was effective January 1, 2021, at which time the 2018 Share Repurchase Plan (described below) and all authorized amounts remaining thereunder terminated as of such date.

In the year ended December 31, 2021, 8,658,153 shares of our common stock were repurchased under the 2020 Share Repurchase Program for approximately $ 175 million at an average price of $ 20.21 per share of common stock.

The 2020 Share Repurchase Program was superseded by the Share Repurchase Program in October 2021.

In June 2018, we announced that the Board had authorized a share repurchase program under which up to $ 500 million of our outstanding common stock may be purchased, and this authorized amount was fully utilized in 2018.

In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $ 1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $ 1.750 billion share repurchase program (collectively, Prior Share Repurchase Program).

The Prior Share Repurchase Program was terminated on January 1, 2021.

Shares of common stock repurchased under the Prior Share Repurchase Program for the years ended December 31, 2020, 2019 and 2018 are reflected in the table below.

$500 Million Board Authorization $1.250 Billion Board Authorization

Total Number of Shares Repurchased Average Price Paid Share Amount Paid for Shares Repurchased Total Number of Shares Repurchased Average Price Paid Share Amount Paid for Shares Repurchased

Year Ended December 31, 2018 21,421,925 $ 23.36 $ 500 12,073,091 $ 22.99 $ 278

Year Ended December 31, 2019 — $ — $ — 26,322,166 $ 24.34 $ 640

Year Ended December 31, 2020 — — — — — —

Totals 21,421,925 $ 23.36 $ 500 38,395,257 $ 23.91 $ 918

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 will be 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.

In the year ended December 31, 2019, 26,322,166 shares of our common stock were repurchased under the 2018 Share Repurchase Program for approximately $ 640 million (including related fees and expenses) at an average price of $ 24.34 per share.

There were no repurchases under the 2018 Share Repurchase Program in the year ended December 31, 2020.

The 2018 Share Repurchase Program was terminated on January 1, 2021.

Preferred Stock

On October 15, 2021 (Series A Issuance Date), we issued of 1,000,000 shares of Series A Preferred Stock in a private offering (Series A Offering).

The net proceeds of the Series A Offering were approximately $ 990 million, after deducting underwriting commissions and offering expenses.

We intend to use the net proceeds from the Series A Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (described above).

On December 10, 2021 (Series B Issuance Date), we issued of 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering).

The net proceeds of the Series B Offering were approximately $ 985 million, after deducting underwriting commissions and offering expenses.

We intend to use the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.

The Series A Preferred Stock and the Series B Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights.

The Series A Preferred Stock may be redeemed at the option of the Company at any time after the Series A First Reset Date (defined below) and in certain other circumstances prior to the Series A First Reset Date.

The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date.

Common Stock — 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.

In February 2019, May 2019, July 2019 and October 2019, the Board declared quarterly dividends of $ 0.125 per share that were paid in March 2019, June 2019, September 2019 and December 2019, respectively.

In February 2020, April 2020, July 2020 and October 2020, the Board declared quarterly dividends of $ 0.135 per share that were paid in March 2020, June 2020, September 2020 and December 2020, respectively.

In February 2021, April 2021, July 2021 and October 2021, the Board declared quarterly dividends of $ 0.15 per share that were paid in March 2021, June 2021, September 2021 and December 2021, respectively.

In February 2022, the Board declared a quarterly dividend of $ 0.17 per share that will be paid in March 2022.

Vistra did not declare or pay any dividends during the year ended December 31, 2018.

Preferred Stock — The annual dividend rate on each share of Series A Preferred Stock is 8.0 % from the Series A Issuance Date to, but excluding October 15, 2026 (Series A First Reset Date).

On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S.

Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07 %), plus a spread of 6.93 % per annum.

The Series A Preferred Stock has a liquidation preference of $ 1,000 per share, plus accumulated but unpaid dividends.

Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board.

In February 2022, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2022.

The annual dividend rate on each share of Series B Preferred Stock is 7.0 % from the Series B Issuance Date to, but excluding December 15, 2026 (Series B First Reset Date).

On and after the Series B First Reset Date, the dividend rate on each share of Series B Preferred Stock shall equal the five-year U.S.

Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.26 %), plus a spread of 5.74 % per annum.

The Series B Preferred Stock has a liquidation preference of $ 1,000 per share, plus accumulated but unpaid dividends.

Cumulative cash dividends on the Series B Preferred Stock are payable semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board.

Dividend Restrictions

1 unchanged sentence

As of December 31, 2021, Vistra Operations can distribute approximately $ 7.3 billion to Parent under the Credit Facilities Agreement without the consent of any party.

The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $ 1.1 billion, $ 3.9 billion and $ 4.7 billion during the years ended December 31, 2020, 2019 and 2018, respectively.

The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $ 405 million, $ 1.1 billion and $ 3.9 billion during the years ended December 31, 2021, 2020 and 2019, respectively.

Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses.

As of December 31, 2020, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled approximately $ 1.2 billion.

As of December 31, 2021, all of the restricted net assets of Vistra Operations may be distributed to Parent.

In addition to the restrictions under the Credit Facilities Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year.

Under the terms of the Series A Preferred Stock and the Series B Preferred Stock, unless full cumulative dividends have been or contemporaneously are being paid or declared and a sum sufficient for the payment thereof set apart for payment on all outstanding Series A Preferred Stock (and any parity securities) and Series B Preferred Stock (and any parity securities), respectively, with respect to dividends through the most recent dividend payment dates, (i) no dividend may be declared or paid or set apart for payment on any junior security (other than a dividend payable solely in junior securities with respect to both dividends and the liquidation, winding-up and dissolution of our affairs), including our common stock, and (ii) we may not redeem, purchase or otherwise acquire any parity security or junior security, including our common stock, in each case subject to certain exceptions as described in the certificate of designation of the Series A Preferred Stock and the Series B Preferred Stock, respectively.

Accumulated Other Comprehensive Income

3 unchanged sentences

Accordingly, upon exercise, a warrant holder would effectively pay $ 53.68 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received.

In July 2021, in accordance with the terms of the warrant agreement, the exercise price of each warrant was adjusted downward to $ 34.54 (subject to further adjustment from time to time), or $ 52.98 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received.

As of December 31, 2021, nine million warrants expiring in 2024 were outstanding.

60 unchanged sentences

Financial transmission rights 122 ( 34 ) 88 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 30 ) to $ 10 $ ( 9 )

Other (h) 14 ( 21 ) ( 7 )

Natural gas 29 ( 86 ) ( 57 ) Income Approach Gas basis (h) $ ( 1 ) to $ 16 $ 8

Coal 61 — 61 Income Approach Probability of default (i) — % to 40 % 20 %

Recovery rate (j) — % to 40 % 20 %

Other (k) 25 ( 3 ) 22

Total $ 442 $ ( 802 ) $ ( 360 )

2 unchanged sentences

Electricity purchases and sales $ 61 $ ( 90 ) $ ( 29 ) Income Approach Hourly price curve shape (c) $ — to $ 85 $ 43

Illiquid delivery periods for ERCOT hub power prices and heat rates (d) $ 20 to $ 120 $ 70

Illiquid delivery periods for hub power prices and heat rates (d) $ 25 to $ 125 $ 75

Options 38 ( 56 ) ( 18 ) Option Pricing Model Gas to power correlation (e) 30 % to 100 % 64 %

1 unchanged sentence

Financial transmission rights 92 ( 16 ) 76 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 5 ) to $ 50 $ 22

Other (h) 17 ( 46 ) ( 29 )

Natural gas 7 ( 14 ) ( 7 ) Income Approach Gas basis (h) $ ( 1 ) to $ — $ —

Coal 1 ( 5 ) ( 4 ) Income Approach Probability of default (i) — % to 40 % 20 %

Recovery rate (j) — % to 40 % 20 %

Other (k) 6 ( 2 ) 4

Total $ 205 $ ( 183 ) $ 22

6 unchanged sentences

(d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT heat rate variability.

(e) Primarily based on the historical forward correlation and volatility within ERCOT.

(e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM.

(f) While we use the market approach, there is insufficient market data to consider the valuation liquid.

(g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.

(h) Other includes contracts for natural gas, coal and environmental allowances.

(h) Primarily based on the historical forward PJM and Northeast gas basis prices.

(i) Estimate of the range of probabilities of default based on past experience, the length of the contract, and both the Company's and the counterparty's credit ratings.

(j) Estimate of the default recovery rate based on historical corporate rates.

(k) Other includes contracts for environmental allowances.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2021, 2020 and 2019.

3 unchanged sentences

2021 2020 2019

Net liability balance at beginning of period $ ( 74 ) $ ( 135 ) $ ( 53 )

Total unrealized valuation gains (losses) ( 5 ) 8 ( 363 )

Purchases, issuances and settlements (a):

Net asset (liability) balance at beginning of period $ 22 $ ( 74 ) $ ( 135 )

Total unrealized valuation gains (losses) (a) ( 53 ) ( 5 ) 8

Purchases, issuances and settlements (b):

Purchases 114 164 176

1 unchanged sentence

Settlements ( 314 ) ( 90 ) ( 64 )

Transfers into Level 3 (b) ( 2 ) 10 4

Transfers out of Level 3 (b) 57 12 133

Net liabilities assumed in connection with the Merger — — ( 37 )

Net change (c) 96 61 ( 82 )

Transfers into Level 3 (c) ( 2 ) ( 2 ) 10

Transfers out of Level 3 (c) ( 91 ) 57 12

Net change (d) ( 382 ) 96 61

Net asset (liability) balance at end of period $ ( 360 ) $ 22 $ ( 74 )

Unrealized valuation gains (losses) relating to instruments held at end of period $ ( 364 ) $ 18 $ ( 61 )

(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income.

(a) During the year ended December 31, 2021, includes a net loss of $ 341 million due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

(b) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income.

Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.

(b) Includes transfers due to changes in the observability of significant inputs.

All Level 3 transfers during the periods presented are in and out of Level 2.

For the year ended December 31, 2020, transfers out of Level 3 primarily consist of gas, power and coal derivatives where forward pricing inputs have become observable.

For the years ended December 31, 2019 and 2018, transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.

For the year ended December 31, 2021, transfers into Level 3 primarily consist of natural gas, emissions and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.

For the year ended December 31, 2020, transfers out of Level 3 primarily consist of natural gas, power and coal derivatives where forward pricing inputs have become observable.

For the year ended December 31, 2019, transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.

(d) Activity excludes change in fair value in the month positions settle.

Substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our consolidated statements of operations.

17 unchanged sentences

Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.

During the year ended December 31, 2021, a net loss of $ 298 million was recognized in operating revenues due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

These amounts are reflected in commodity contracts derivative liabilities at December 31, 2021.

December 31, 2021

14 unchanged sentences

Net assets (liabilities) $ 858 $ 72 $ ( 933 ) $ ( 404 ) $ ( 407 )

At December 31, 2020 and 2019, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects.

As of December 31, 2021 and 2020, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pre-tax effect of derivative gains (losses) on net income, including realized and unrealized effects.

Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.

55 unchanged sentences

We have concentrations of credit risk with the counterparties to our derivative contracts.

At December 31, 2020, total credit risk exposure to all counterparties related to derivative contracts totaled $ 1.085 billion (including associated accounts receivable).

The net exposure to those counterparties totaled $ 293 million at December 31, 2020 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $ 85 million.

At December 31, 2020, the credit risk exposure to the banking and financial sector represented 65 % of the total credit risk exposure and 18 % of the net exposure.

As of December 31, 2021, total credit risk exposure to all counterparties related to derivative contracts totaled $ 3.742 billion (including associated accounts receivable).

The net exposure to those counterparties totaled $ 1.417 billion at December 31, 2021 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to ERCOT totaling $ 619 million.

As of December 31, 2021, the credit risk exposure to the banking and financial sector represented 54 % of the total credit risk exposure and 4 % of the net exposure.

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings.

19 unchanged sentences

The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.

Prior to the Merger, Dynegy provided pension and OPEB benefits to certain of its employees and retirees.

At the Merger Date, Vistra assumed these plans and the excess of the benefit obligations over the fair value of plan assets was recognized as a liability (see Note 2).

Benefit obligations assumed totaled $ 539 million and the fair value of plan assets assumed totaled $ 459 million, and the net unfunded liability was recorded as $ 15 million to other noncurrent assets, $ 2 million to other current liabilities and $ 93 million to other noncurrent liabilities in the consolidated balance sheets.

Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra.

13 unchanged sentences

Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

Detailed Information Regarding Pension Benefits

Detailed Information Regarding Pension Plans and OPEB Benefits

The following information is based on a December 31, 2021, 2020 and 2019 measurement dates:

Year Ended December 31,

Retirement Plan OPEB Plans

Year Ended December 31, Year Ended December 31,

2021 2020 2019 2021 2020 2019

Assumptions Used to Determine Net Periodic Pension Cost:

Discount rate (Vistra Plan) 3.24 % 4.37 % 3.74 %

Discount rate (Dynegy Plan and EEI Plan) 3.24 % 4.37 % 4.05 %

Assumptions Used to Determine Net Periodic Pension and Benefit Cost:

Discount rate 2.50 % 3.24 % 4.37 % 2.51 % 3.25 % 4.35 %

Expected rate of compensation increase 3.41 % 3.29 % 3.35 %

Interest crediting rate for cash balance 3.00 % 3.50 % 3.50 %

Expected return on plan assets (Vistra Plan) 3.77 % 4.44 % 4.80 %

1 unchanged sentence

Expected return on plan assets (EEI Plan) 4.72 % 5.45 % 5.56 %

Expected rate of compensation increase (Vistra Plan) 3.29 % 3.35 % 3.62 %

Expected rate of compensation increase (Dynegy Plan and EEI Plan) 3.29 % 3.35 % 3.50 %

Interest crediting rate for cash balance plans (Vistra Plan) 3.50 % 3.50 % 3.50 %

Interest crediting rate for cash balance plans (Dynegy Plan and EEI Plan) 3.50 % 3.50 % 4.25 %

Components of Net Pension Cost:

Expected return on plan assets (EEI Union) 6.79 % 7.07 % 5.36 %

Expected return on plan assets (EEI Salaried) 2.95 % 3.43 % 4.70 %

Components of Net Pension and Benefit Cost:

Service cost $ 5 $ 6 $ 7 $ 1 $ 2 $ 2

2 unchanged sentences

Amortization of unrecognized amounts 3 1 — 5 4 3

Immediate pension cost 7 3 1

Net periodic pension cost $ 11 $ 9 $ 14

Immediate pension and postretirement benefit cost — 7 3 — ( 1 ) 1

Net periodic pension and OPEB cost $ 6 $ 11 $ 9 $ 8 $ 7 $ 11

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:

Net loss $ 17 $ 11 $ 14

Net (gain) loss and prior service (credit) cost $ ( 29 ) $ 17 $ 11 $ ( 12 ) $ 5 $ —

Total recognized in net periodic benefit cost and other comprehensive income $ ( 23 ) $ 28 $ 20 $ ( 4 ) $ 12 $ 11

Assumptions Used to Determine Benefit Obligations:

Assumptions Used to Determine Benefit Obligations at Period End:

Discount rate 2.84 % 2.50 % 3.24 % 2.87 % 2.51 % 3.25 %

1 unchanged sentence

Interest crediting rate for cash balance plans 3.00 % 3.00 % 3.50 %

Net Actuarial Gains (Losses)

Retirement Plan — For the year ended December 31, 2021, the net actuarial gain of $ 24 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets and gains attributable to actual asset performance exceeding expectations, partially offset by losses attributable to demographic assumption updates to reflect recent plan experience, actuarial assumption updates to reflect current market conditions, plan amendments, settlements and plan experience different than expected.

For the year ended December 31, 2020, the net actuarial loss of $ 29 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect current market conditions and plan amendments, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy updates, annuity purchases, lump sum windows and plan experience different than expected.

For the year ended December 31, 2019, the net actuarial loss of $ 16 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect current market conditions, annuity purchases, plan amendments and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations and life expectancy updates.

For the year ended December 31, 2018, the net actuarial loss of $ 14 million was driven by losses attributable to actual asset performance falling short of expectations and plan experience different than expected, partially offset by gains attributable to increasing discount rates due to changes in the corporate bond markets, economic assumption updates to reflect current market conditions and life expectancy projection updates.

Year Ended December 31,

Change in Pension Obligation:

OPEB Plans — For the year ended December 31, 2021, the net actuarial gain of $ 7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, plan experience different than expected, updates to health care claims and trend assumptions and actual asset performance exceeding expectations, partially offset by losses attributable to demographic assumption updates and life expectancy updates.

For the year ended December 31, 2020, the net actuarial loss of $ 10 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy updates and updates to health care claims and trend assumptions.

For the period ended December 31, 2019, the net actuarial loss of $ 5 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy changes, updates to health care related assumptions and changes due to the repeal of certain Affordable Care Act fees.

Retirement Plan OPEB Plans

Year Ended December 31, Year Ended December 31,

2021 2020 2021 2020

Change in Pension and Postretirement Benefit Obligations:

Projected benefit obligation at beginning of period $ 643 $ 674 $ 157 $ 151

1 unchanged sentence

Interest cost 16 20 4 4

Participant contributions — — 3 3

Lump-sum window — ( 6 ) — —

7 unchanged sentences

Employer contributions 1 16 9 9

Participant contributions — — 3 3

Lump-sum window — ( 6 ) — —

8 unchanged sentences

Amounts Recognized in the Balance Sheet Consist of:

Other noncurrent assets $ — $ — $ 26 $ 23

Other current liabilities — — ( 9 ) ( 9 )

Other noncurrent liabilities ( 135 ) ( 158 ) ( 124 ) ( 134 )

1 unchanged sentence

Amounts Recognized in Accumulated Other Comprehensive Income Consist of:

Net (loss) $ ( 42 ) $ ( 24 )

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.

Net loss and prior service cost $ ( 13 ) $ ( 42 ) $ 8 $ 20

Fair Value Measurement of Pension and OPEB Plan Assets

Retirement Plan — As of December 31, 2021 and 2020, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) and consisted of the following:

Asset Category:

Cash commingled trusts 11 11

Equity securities:

Global equities 149 153

Fixed income securities:

Corporate bonds (a) 199 207

Government bonds 31 37

Other (b) 30 32

Real estate 50 45

Total assets measured at net asset value $ 470 $ 485

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Consists primarily of high-yield bonds, emerging market debt and bank loans.

OPEB Plans — As of December 31, 2021 and 2020, the Vistra OPEB plan assets measured at fair value on a recurring basis totaled $ 39 million and $ 37 million, respectively.

At December 31, 2021, assets consisted of $ 37 million of comingled funds valued at net asset value and $ 2 million of municipal bond and cash equivalent mutual funds classified as Level 1.

At December 31, 2020, assets consisted of $ 29 million of U.S.

equities classified as Level 1 and $ 8 million of U.S.

Treasuries and municipal bonds classified as Level 2.

Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO)

The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets.

Pension Plans with PBO and ABO in Excess Of Plan Assets:

2 unchanged sentences

Plan assets $ 470 $ 485

Pension Plan Investment Strategy and Asset Allocations

Retirement Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions.

12 unchanged sentences

Credit strategies 3 % - 7 % 6 % - 10 % 7 % - 11 %

Expected Long-Term Rate of Return on Assets Assumption

Retirement Plan Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies.

8 unchanged sentences

Weighted average 4.2 % 4.8 % 4.9 %

Fair Value Measurement of Pension Plan Assets

At December 31, 2020 and 2019, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) and consisted of the following:

Year Ended December 31,

Asset Category:

Cash commingled trusts 11 10

Equity securities:

Global equities 153 169

Fixed income securities:

Corporate bonds (a) 207 211

Government bonds 37 50

Other (b) 32 37

Real estate 45 51

Total assets measured at net asset value $ 485 $ 528

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Consists primarily of high-yield bonds, emerging market debt and bank loans.

Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on a December 31, 2020 measurement date:

Year Ended December 31,

2020 2019 2018

Assumptions Used to Determine Net Periodic Benefit Cost:

Discount rate (Vistra Plan) 3.25 % 4.35 % 3.67 %

Discount rate (Split-Participant Plan) 3.25 % 4.35 % 3.67 %

Discount rate (Dynegy Plan) 3.25 % 4.35 % 4.04 %

Expected return on plan assets (EEI Union) 7.07 % 5.36 % 5.10 %

Expected return on plan assets (EEI Salaried) 3.43 % 4.70 % 4.47 %

Components of Net Postretirement Benefit Cost:

Service cost $ 2 $ 2 $ 2

Interest cost 4 6 5

Expected return on plan assets ( 2 ) ( 1 ) ( 1 )

Amortization of unrecognized amounts 4 3 3

Immediate postretirement benefit cost ( 1 ) 1 —

Net periodic OPEB cost $ 7 $ 11 $ 9

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:

Net (gain) loss and prior service (credit) cost $ 5 $ — $ ( 6 )

Total recognized in net periodic benefit cost and other comprehensive income $ 12 $ 11 $ 3

Assumptions Used to Determine Benefit Obligations at Period End:

Discount rate 2.51 % 3.25 % 4.35 %

For the year ended December 31, 2019, the net actuarial loss of $ 5 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy changes, updates to health care related assumptions and changes due to the repeal of certain Affordable Care Act fees.

For the period ended December 31, 2018, the net actuarial loss of $ 7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, life expectancy projection updates and updates to health care related assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and plan experience different than expected.

Year Ended December 31,

Change in Postretirement Benefit Obligation:

Benefit obligation at beginning of year $ 151 $ 144

Service cost 2 2

Interest cost 4 6

Participant contributions 3 3

Actuarial loss 12 10

Benefits paid ( 15 ) ( 14 )

Benefit obligation at end of year $ 157 $ 151

Change in Plan Assets:

Fair value of assets at beginning of year $ 34 $ 29

Employer contributions 9 9

Participant contributions 3 3

Benefits paid ( 13 ) ( 13 )

Actual gain on assets 4 6

Fair value of assets at end of year $ 37 $ 34

Funded Status:

Benefit obligation $ ( 157 ) $ ( 151 )

Fair value of assets 37 34

Funded status at end of year $ ( 120 ) $ ( 117 )

Amounts Recognized on the Balance Sheet Consist of:

Other noncurrent assets $ 23 $ 18

Other current liabilities $ ( 9 ) $ ( 9 )

Other noncurrent liabilities ( 134 ) ( 126 )

Net liability recognized $ ( 120 ) $ ( 117 )

Amounts Recognized in Accumulated Other Comprehensive Income Consist of:

Net loss and prior service cost $ 20 $ 15

Benefit Plan Assumed Health Care Cost Trend Rates

The following tables provide information regarding the assumed health care cost trend rates.

December 31, 2020 December 31, 2019

Assumed Health Care Cost Trend Rates-Not Medicare Eligible:

7 unchanged sentences

Year that the rate reaches the ultimate trend rate 2031 2030

Fair Value Measurement of OPEB Plan Assets

At December 31, 2020 and 2019, the Vistra OPEB plan assets measured at fair value on a recurring basis totaled $ 37 million and $ 34 million, respectively, and consisted of $ 29 million and $ 26 million, respectively, of U.S.

equities classified as Level 1 and $ 8 million and $ 8 million, respectively, of U.S.

Treasuries and municipal bonds classified as Level 2.

Significant Concentrations of Risk

6 unchanged sentences

Contributions

Contributions to the Retirement Plan for the years ended December 31, 2020, 2019 and 2018 totaled $ 16 million, zero and $ 12 million, respectively, and $ 1 million in contributions are expected to be made in 2021.

OPEB plan funding for the years ended December 31, 2020, 2019 and 2018 totaled $ 9 million, $ 9 million and $ 8 million, respectively, and funding in 2021 is expected to total $ 9 million.

Contributions to the Retirement Plan for the years ended December 31, 2021, 2020 and 2019 totaled $ 1 million, $ 16 million and zero , respectively, and no contributions are expected to be made in 2022.

OPEB plan funding for each year ended December 31, 2021, 2020 and 2019 totaled $ 9 million and funding in 2022 is expected to total $ 9 million.

Future Benefit Payments

25 unchanged sentences

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders.

Assumption of Dynegy Stock Compensation Plans

At the Merger Date, Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra's common stock, after giving effect to the Exchange Ratio.

Instrument Type Dynegy Awards Prior to the Merger Date Vistra Awards Converted at the Merger Date Fair Value of Awards (a) at the Merger Date

Stock Options 4,096,027 2,670,610 $ 10

Restricted Stock Units 5,718,148 3,056,689 61

Performance Units 1,538,133 938,721 18

(a) $ 26 million was attributable to pre-combination service and considered part of the purchase price (see Note 2).

$ 33 million was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger.

$ 30 million will be amortized as compensation expense over the remaining service period and is recorded in additional paid in capital in the consolidated balance sheet.

Stock-Based Compensation Expense

13 unchanged sentences

These options may be exercised over either three- or four-year graded vesting periods and will expire 10 years from the grant date.

Issuance of Merger-related Stock Options — At the Merger Date, we issued 5.2 million stock options to certain members of management, which are subject to performance and service conditions for vesting.

The performance condition is based on the Company's achievement of certain merger related targets which were achieved as of December 31, 2019.

Compensation cost was recognized in 2018, 2019 and 2020 based on graded vesting over 4 and 5 years since the date of issuance because we estimated achievement of the target was likely to occur.

Stock options outstanding at December 31, 2021 are all held by current or former employees.

10 unchanged sentences

Exercisable at December 31, 2021 7,234 $ 17.60 5.7 $ 42.1

At December 31, 2020, $ 27 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years.

As of December 31, 2021, $ 12 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 1 year.

Restricted Stock Units

9 unchanged sentences

Total nonvested at end of period 2,811 $ 22.57

At December 31, 2020, $ 27 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years.

Performance Stock Units

In October 2017, February 2019 and February 2020, we issued Performance Stock Units (PSUs) to certain members of management.

All PSUs have a three years performance period and a payout opportunity of 0 - 200 % of target ( 100 %), which is intended to be settled in shares of Vistra common stock.

As of December 31, 2019, we had not yet established the final terms of the previously issued PSUs relevant to vesting (scorecard, thresholds, and targets) for the entire measurement period;

therefore, a grant date for financial accounting purposes had not occurred.

In February 2020, the final terms were established for the October 2017 issuance and a grant date for financial accounting purposes had occurred.

In March 2020, we began recognizing compensation cost ratably over the remaining 13 -month vesting period for the October 2017 issuance.

In February 2021, the final terms were established for the February 2019 issuance and a grant date for financial accounting purposes has occurred.

In March 2021, we will begin recognizing compensation cost ratably over the remaining 12 -month vesting period for the February 2019 issuance.

Additional PSUs were issued to certain members of management in February 2021 with the grant date for accounting purposes not yet established.

The following table summarizes our PSU activity:

Year Ended December 31, 2020

Performance Stock Units

(in thousands) Weighted

Average Grant Date Fair Value

Total nonvested at beginning of period — $ —

Granted 473 $ 23.43

Vested ( 21 ) $ 23.43

Forfeited ( 1 ) $ 23.43

Total nonvested at end of period 451 $ 23.43

At December 31, 2020, $ 4 million of unrecognized compensation cost related to unvested performance stock units granted under the 2016 Incentive Plan is expected to be recognized over a weighted average period of approximately 3 months.

As of December 31, 2021, $ 38 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years.

We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis.

All PSUs have a three year performance period and a payout opportunity of 0 - 200 % of target ( 100 %), which is intended to be settled in shares of Vistra common stock.

We recognized compensation expense associated with PSUs of $ 9 million, $ 15 million and zero for the years ended December 31, 2021, 2020 and 2019, respectively.

As of December 31, 2021, we have $ 2 million of unrecognized compensation cost associated with PSUs.

RELATED PARTY TRANSACTIONS

1 unchanged sentence

Registration Rights Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra common stock held by such selling stockholders.

In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra common stock held by certain significant stockholders pursuant to the Registration Rights Agreement, which was declared effective by the SEC in May 2017.

The registration statement was amended in March 2018.

Pursuant to the Registration Rights Agreement, in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on Form S-3, which was declared effective by the SEC in July 2018.

Among other things, under the terms of the Registration Rights Agreement:

• if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement;

• the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration (as defined in the Registration Rights Agreement) and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed.

All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us.

Legal fee expenses paid or accrued by Vistra on behalf of the selling stockholders totaled less than $ 1 million during each of the years ended December 31, 2020, 2019 and 2018.

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRA) with certain selling stockholders.

Pursuant to the RRA, we maintain a registration statement on Form S-3 providing for registration of the resale of the Vistra common stock held by such selling stockholders.

In addition, under the terms of the RRA, among other things, if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the RRA the opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.

Tax Receivable Agreement

1 unchanged sentence

See Note 8 for discussion of the TRA.

Share Repurchase Transaction

In November 2018, the disinterested members of the Board considered and approved (in accordance with the Company's corporate governance guidelines) a share repurchase transaction, whereby Apollo Management Holdings L.P.

(Apollo) and the Company, in a privately negotiated transaction, agreed for the Company to directly repurchase 5 million of Vistra common shares from Apollo.

This purchase was part of Apollo's larger, 17 million share block trade, with the remaining 12 million shares being sold in a separate unregistered Rule 144 secondary block trade to a broker-dealer, who placed all 12 million shares with institutional investors.

The Company repurchased the 5 million shares at the same discounted price (discounted from the November 19, 2018 closing price) that the participating broker paid for the 12 million shares it purchased, and the Company did not pay any additional fees to Apollo or the participating broker for the 5 million shares it repurchased.

SEGMENT INFORMATION

5 unchanged sentences

• The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments.

Given recent and expected future retirements of certain power plants, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.

• The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S.

19 unchanged sentences

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating segments.

Except as noted in Note 1, the accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1.

Our CODM uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on U.S.

36 unchanged sentences

(1) Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.

(b) Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate and Other net income.

(b) Income tax expense is generally not reflected in net income of the segments but is reflected almost entirely in Corporate and Other net income.

SUPPLEMENTARY FINANCIAL INFORMATION

Impairment of Long-Lived Assets

In the second quarter of 2021, we recognized an impairment loss of $ 38 million related to our Zimmer generation facility in Ohio as a result of a significant decrease in the estimated useful life of the facilities, reflecting a decrease in the economic forecast of the facility and the inability to secure capacity revenues for the plant in the latest PJM capacity auction held in May 2021.

The impairments are reported in our Sunset segment and include a $ 33 million write-down of property, plant and equipment and a $ 5 million write-down of inventory.

In the third quarter of 2020, we recognized impairment losses of $ 173 million related to our Kincaid coal generation facility in Illinois and $ 99 million related to our Zimmer coal generation facility in Ohio, each as a result of a significant decrease in the estimated useful life of the facility, reflecting our recently announced plan to retire both facilities by the end of 2027 in response to the final CCR rule (see Notes 4 and 13).

The impairment losses are reported in our Sunset segment and include a $ 260 million write-down of property, plant and equipment and a $ 12 million write-down of inventory.

In determining the fair value of the impaired assets, we equally weighted a market approach valuation based on transactions of similar assets and an income approach valuation discounting our projected cash flows through the respective plant retirement dates.

In the first quarter of 2020, we recognized an impairment loss of $ 52 million related to our Joppa/EEI coal generation facility in Illinois as a result of a significant decrease in the estimated useful life of the facility, reflecting a decrease in the economic forecast of the facility and changes to the operating assumption based on lower forecasted wholesale electricity prices.

1 unchanged sentence

The impairments are reported in our Sunset segment and include a $ 45 million write-down of property, plant and equipment, a $ 32 million write-down of intangible assets and a $ 7 million write-down of inventory.

In determining the fair value of the impaired assets, we equally weighted a market approach based on transactions of similar assets and an income approach discounting our projected cash flows through the respective plant retirement dates.

Interest Expense and Related Charges

2 unchanged sentences

Interest paid/accrued $ 480 $ 467 $ 576

Unrealized mark-to-market net losses on interest rate swaps 155 220 5

Unrealized mark-to-market net (gains) losses on interest rate swaps ( 134 ) 155 220

Amortization of debt issuance costs, discounts and premiums 30 18 9

3 unchanged sentences

Total interest expense and related charges $ 384 $ 630 $ 797

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 3.88 %, 4.03 % and 4.24 % at December 31, 2020, 2019 and 2018, respectively.

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 3.90 %, 3.88 % and 4.03 % as of December 31, 2021, 2020 and 2019, respectively.

Other Income and Deductions

2 unchanged sentences

Other income:

Insurance settlement (a) $ 6 $ 22 $ 16

Funds released from escrow to settle pre-petition claims of our predecessor (b) — 9 —

Office space sublease rental income (b) — — 8

Sale of land (c) 8 — 3

Insurance settlements (a) $ 88 $ 6 $ 22

Gain on settlement of rail transportation disputes (b) 15 — —

Sale of land (b) 9 8 —

Funds released from escrow to settle pre-petition claims of our predecessor (c) — — 9

Interest income — 2 10

5 unchanged sentences

Total other deductions $ 16 $ 42 $ 15

(a) For the year ended December 31, 2020, $ 3 million reported in the Corporate and Other non-segment, $ 2 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment.

The amounts for the years ended December 31, 2019 and 2018, respectively, are reported in the Texas segment.

(b) Reported in the Corporate and Other non-segment.

Beginning January 1, 2019, our office space sublease rental income related to real estate leases is reported in SG&A expenses in the consolidated statements of operations.

(a) For the year ended December 31, 2021, $ 80 million reported in the Texas segment, $ 7 million reported in the Sunset segment and $ 1 million reported in the Corporate and Other non-segment.

For the year ended December 31, 2020, $ 3 million reported in the Corporate and Other non-segment, $ 2 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment.

For the year ended December 31, 2019, reported in the Texas segment.

(b) Reported in the Asset Closure segment.

(d) Reported in the East segment.

4 unchanged sentences

Amounts related to remediation escrow accounts $ 21 $ 13 $ 19 $ 19

Amounts related to restructuring escrow accounts — — 43 —

Amounts related to Ambit customer deposits — — 19 —

Amounts related to Ambit commodity trading agreement — — 62 —

Amounts related to Ambit letters of credit (Note 11) — — 8 —

Total restricted cash $ 21 $ 13 $ 19 $ 19

2 unchanged sentences

Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.

Pre-Petition Claims — On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged approximately $ 33.8 billion in liabilities subject to compromise.

Initial distributions related to the allowed claims asserted against the TCEH Debtors and the Contributed EFH Debtors commenced subsequent to the Effective Date.

Amounts were held in escrow to (1) distribute to holders of contingent and/or disputed unsecured claims that become allowed and/or (2) make distributions to holders of previously allowed unsecured claims, if applicable.

In December 2019, the Bankruptcy Court entered an order, Docket No.

13982, sustaining the TCEH Debtors' objection to and liquidating the manifested and unmanifested asbestos claims.

As of this filing, the TCEH Debtors believe they have resolved the remaining contingent and/or disputed unsecured claims, and have undertook the necessary steps to modify the claims register accordingly and made final distribution from the escrow to holders of allowed claims.

At December 31, 2019, unresolved claims were recorded in Vistra's consolidated balance sheet as other current liabilities, and the related escrow balance were recorded in Vistra's consolidated balance sheet as current restricted cash.

All non-priority unsecured claims, including asbestos claims arising before the Petition Date, were satisfied solely from the amounts in escrow.

Trade Accounts Receivable

2 unchanged sentences

Trade accounts receivable — net $ 1,397 $ 1,279

Gross trade accounts receivable at December 31, 2020 and 2019 included unbilled retail revenues of $ 468 million and $ 494 million, respectively.

Gross trade accounts receivable as of December 31, 2021 and 2020 included unbilled retail revenues of $ 426 million and $ 468 million, respectively.

Allowance for Uncollectible Accounts Receivable

5 unchanged sentences

Allowance for uncollectible accounts receivable at end of period $ 45 $ 45 $ 36

(a) Includes a $ 6 million increase recorded due to the adoption of ASU 2016-13, Financial Instruments—Credit Losses (see Note 1).

(a) The beginning balance in 2020 includes a $ 6 million increase recorded due to the adoption of ASU 2016-13, Financial Instruments—Credit Losses (see Note 1).

Inventories by Major Category

5 unchanged sentences

Assets related to employee benefit plans (Note 17) 42 41

Miscellaneous other 3 —

Total investments $ 2,049 $ 1,759

1 unchanged sentence

On the Merger Date, we assumed Dynegy's 50 % interest in NELP, a joint venture with NextEra Energy, Inc., which indirectly owned the Bellingham NEA facility and the Sayreville facility.

At December 31, 2019, our investment in NELP totaled $ 123 million.

In December 2019, Dynegy Northeast Generation GP, Inc.

5 unchanged sentences

The loss is reported in our consolidated statements of operations in other deductions.

Equity earnings related to our investment in NELP totaled $ 3 million, $ 14 million and $ 17 million for the years ended December 31, 2020, 2019 and 2018, respectively, recorded in equity in earnings of unconsolidated investment in our consolidated statements of operations.

We received distributions totaling $ 3 million, $ 22 million and $ 17 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Equity earnings related to our investment in NELP totaled $ 3 million and $ 14 million for the years ended December 31, 2020 and 2019, respectively, recorded in equity in earnings of unconsolidated investment in our consolidated statements of operations.

We received distributions totaling $ 3 million and $ 22 million for the years ended December 31, 2020 and 2019, respectively.

Nuclear Decommissioning Trust

10 unchanged sentences

The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds.

The debt securities had an average coupon rate of 2.91 % and 3.42 % at December 31, 2020 and 2019, respectively, and an average maturity of 10 years and 9 years at December 31, 2020 and 2019, respectively.

The debt securities had an average coupon rate of 2.54 % and 2.91 % as of December 31, 2021 and 2020, respectively, and an average maturity of 10 years as of both December 31, 2021 and 2020.

(b) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S.

1 unchanged sentence

equity investments.

Debt securities held at December 31, 2020 mature as follows:

Debt securities held as of December 31, 2021 mature as follows:

$ 247 million in one to five years, $ 190 million in five to 10 years and $ 242 million after 10 years.

20 unchanged sentences

There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor.

As of December 31, 2021 and 2020, asbestos removal liabilities totaled $ 3 million and zero million , respectively.

We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets.

However, because the period of remediation is indeterminable no removal liabilities have been recognized.

At December 31, 2020, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $ 1.585 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust.

As of December 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $ 1.635 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust.

Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our consolidated balance sheet of $ 325 million in other noncurrent liabilities and deferred credits.

4 unchanged sentences

Adjustment for change in estimates — 16 ( 1 ) 15

Obligations assumed in the Merger — 2 475 477

Payments — ( 76 ) ( 24 ) ( 100 )

Liability at December 31, 2018 1,276 442 655 2,373

Accretion 44 22 31 97

Adjustment for change in estimates — 16 ( 1 ) 15

Adjustment for obligations assumed through acquisitions — — ( 3 ) ( 3 )

7 unchanged sentences

Liability at December 31, 2020 1,585 359 492 2,436

Accretion 50 16 22 88

Adjustment for change in estimates — 13 1 14

Payments — ( 68 ) ( 20 ) ( 88 )

Liability at December 31, 2021 1,635 320 495 2,450

Less amounts due currently — ( 90 ) ( 14 ) ( 104 )

9 unchanged sentences

Retirement and other employee benefits (Note 17) $ 276 $ 312

Winter Storm Uri impact (a) 261 —

Identifiable intangible liabilities (Note 6) 147 289

3 unchanged sentences

Liability for third-party remediation 17 31

Environmental allowances — 52

Accrued severance costs 39 54

1 unchanged sentence

Total other noncurrent liabilities and deferred credits $ 1,489 $ 1,131

(a) Includes the allocation of ERCOT default uplift charges and future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

Fair Value of Debt

5 unchanged sentences

Vistra Operations Senior Notes Level 2 7,880 8,193 6,634 7,204

Vistra Senior Notes Level 2 — — 774 772

Forward Capacity Agreements Level 3 211 211 45 45

25 unchanged sentences

Land transferred with liability transfers $ — $ — $ 16

Vistra common stock issued in the Merger (Notes 2 and 14) $ — $ — $ 2,245

(a) For the years ended December 31, 2020, 2019 and 2018, we paid federal income taxes of zero , zero and $ 45 million, respectively, paid state income taxes of $ 40 million, $ 42 million and $ 27 million, respectively, received federal tax refunds of $ 170 million, $ 115 million and zero , respectively, and received state tax refunds of $ 10 million, $ 3 million and $ 5 million, respectively.

(a) For the years ended December 31, 2021, 2020 and 2019, we paid state income taxes of $ 52 million, $ 40 million and $ 42 million, respectively, received federal tax refunds of zero , $ 170 million and $ 115 million, respectively, and received state tax refunds of $ 2 million, $ 10 million and $ 3 million, respectively.

(b) Represents property, plant and equipment accruals during the period for which cash has not been paid as of the end of the period.

1 unchanged sentence

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data