What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2023-03-01 compared with 2022-02-25 · 531 added, 610 removed, 1748 unchanged (39% of the section changed)

6 unchanged sentences

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2022, expressed an unqualified opinion on the Company’s internal control over financial reporting.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2023, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

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

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

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

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

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

(3) forward purchase contracts for power, natural gas, coal, environmental allowances, congestion revenue rights and financial transmission rights;

and (4) retail sales contracts.

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

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Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the following, among others:

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

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

• We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2022, to confirm our understanding of the types of instruments outstanding.

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

• We assessed the consistency by which management has applied illiquid price curves and significant unobservable valuation inputs.

• 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.

Valuation Allowance for Deferred Tax Assets — Refer to Notes 1 and 6 to the financial statements

Critical Audit Matter Description

As described in Note 6 to the consolidated financial statements, as of December 31, 2022, the Company has net deferred tax assets of $1.709 million.

The Company evaluates the realizability of the deferred tax assets, and to the extent that the Company estimates that it is more likely than not that a benefit will not be realized, a valuation allowance is recognized to reduce the deferred tax assets to an amount that is more likely than not to be realized.

As a part of this evaluation, the Company assesses all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations, to determine whether sufficient future taxable income will be generated to realize existing deferred tax assets.

The Company has identified objective and verifiable negative evidence, most notably, in the form of cumulative losses on an unadjusted basis over the preceding 12 quarters ended December 31, 2022.

When determining whether cumulative losses in recent years exist, an entity should generally not exclude nonrecurring items from its results.

It may, however, be appropriate for the entity to exclude nonrecurring items when projecting future income in connection with its determination of the amount of the valuation allowance needed.

The Company evaluated its historical earnings after adjusting for certain nonrecurring items for purposes of projecting future income, performed scheduling of the reversal of temporary differences, and considered other evidence giving rise to positive and negative evidence.

On the basis of this evaluation, the Company considered the relative weight of the available negative and positive evidence and concluded its net deferred tax assets of $1,709 million, inclusive of a $63 million valuation allowance, will be realizable.

We identified the valuation of net deferred tax assets as a critical audit matter because of the significant judgments made by management in projecting future income.

Our audit procedures required a high degree of auditor judgment and an increased extent of effort, including the need to involve our tax specialists, to evaluate the reasonableness of management's estimates of the projected future income.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the determination that it is more likely than not that sufficient taxable income will be generated in the future to realize deferred tax assets included the following, among others:

• We tested the effectiveness of management’s controls over deferred tax assets, estimates of projected income, and the evaluation of whether it is more likely than not that the deferred tax assets will be realized

• With the assistance of our tax specialists, we evaluated:

◦ the Company’s adjusted book income calculation, including the accuracy the 3-year cumulative income/loss position as adjusted for nonrecurring items

◦ the reasonableness of the methods, assumptions, and judgments used by management, including the evaluation of the relative weight of the positive and negative evidence available in management's assessment to determine whether a valuation allowance was necessary

◦ the future reversals of taxable temporary differences and whether the sources of management’s income were of the appropriate character and sufficient to utilize the deferred tax assets under the relevant tax law, considering attribute expiry

◦ the completeness and accuracy of the deferred tax assets included in the Company’s scheduling exercise to ensure all attributes were appropriately included

◦ any tax law changes that would impact the Company’s ability to utilize deferred tax assets and evaluated whether the Company’s analysis appropriately factors in the law changes

• We evaluated management’s ability to accurately estimate income by comparing actual results to management’s historical estimates and evaluating whether there have been any changes that would affect management’s ability to continue to accurately estimate income.

• We assessed the consistency of projected income with evidence obtained in other areas of the audit.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 25, 2022

March 1, 2023

We have served as the Company's auditor since 2002.

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Equity in earnings of unconsolidated investment (Note 20) — — 4

Income (loss) before income taxes ( 1,722 ) 890 1,216

Net income (loss) before income taxes ( 1,560 ) ( 1,722 ) 890

Income tax (expense) benefit (Note 6) 350 458 ( 266 )

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Net income (loss) attributable to Vistra ( 1,227 ) ( 1,274 ) 636

Cumulative dividends attributable to preferred stock ( 150 ) ( 21 ) —

Net income (loss) attributable to Vistra common stock $ ( 1,377 ) $ ( 1,295 ) $ 636

Weighted average shares of common stock outstanding:

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Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $ 7 , $ 9 and $( 5 ))

32 ( 18 ) ( 8 )

Total other comprehensive income (loss) 23 32 ( 18 )

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Capital expenditures, including nuclear fuel purchases and LTSA prepayments ( 1,301 ) ( 1,033 ) ( 1,259 )

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

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

Proceeds from sales of nuclear decommissioning trust fund securities 670 483 433

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Proceeds from sale of assets 21 30 24

Proceeds from sale of nuclear fuel 57 — —

Other, net ( 4 ) ( 4 ) ( 11 )

Cash used in investing activities ( 1,239 ) ( 1,153 ) ( 1,572 )

CONSOLIDATED STATEMENTS OF CASH FLOWS

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2022 2021 2020

Other, net ( 4 ) ( 11 ) ( 6 )

Cash used in investing activities ( 1,153 ) ( 1,572 ) ( 1,717 )

Cash flows — financing activities:

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Repayments under Revolving Credit Facility ( 1,500 ) ( 1,450 ) ( 1,425 )

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

Borrowings under Commodity-Linked Facility 3,150 — —

Repayments under Commodity-Linked Facility ( 2,750 ) — —

Debt issuance costs ( 31 ) ( 13 ) ( 17 )

Share repurchases ( 1,949 ) ( 471 ) —

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

Dividends paid to common stockholders ( 302 ) ( 290 ) ( 266 )

Dividends paid to preferred stockholders ( 151 ) — —

Other, net 31 ( 21 ) ( 5 )

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Investments (Note 20) 1,729 2,049

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

Property, plant and equipment — net (Note 20) 12,554 13,056

Operating lease right-of-use assets (Note 11) 51 40

Goodwill (Note 5) 2,583 2,583

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Current liabilities:

Short-term borrowings (Note 10) $ 650 $ —

Accounts receivable financing (Note 9) 425 —

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Margin deposits related to commodity contracts 39 39

Accrued income taxes — 16

Accrued taxes other than income 199 207

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shares outstanding:

December 31, 2021 — 1,000,000 ;

December 31, 2020 — zero );

December 31, 2022 and 2021 — 1,000,000 ;

Series B (liquidation preference — $ 1,000 ;

shares outstanding:

December 31, 2021 — 1,000,000 ;

December 31, 2020 — zero )

December 31, 2022 and 2021 — 1,000,000 )

Common stock (par value — $ 0.01 ;

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Retained deficit ( 3,643 ) ( 1,964 )

Accumulated other comprehensive loss ( 16 ) ( 48 )

Accumulated other comprehensive income (loss) 7 ( 16 )

Stockholders' equity 4,902 8,291

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December 31, 2019

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

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

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

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

Net loss — — — — 928 — 928 ( 2 ) 926

Net income (loss) — — — — 636 — 636 ( 12 ) 624

Dividends declared on common stock — — — — ( 266 ) — ( 266 ) — ( 266 )

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

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

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

Change in accumulated other comprehensive income (loss) — — — — — ( 18 ) ( 18 ) — ( 18 )

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

Other — — — — ( 1 ) — ( 1 ) — ( 1 )

December 31, 2020

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

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

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

Stock repurchases — — ( 585 ) — — — ( 585 ) — ( 585 )

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

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

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

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

Change in accumulated other comprehensive income (loss) — — — — — 32 32 — 32

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

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December 31, 2021

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

Stock repurchases ( 1,837 ) ( 1,837 ) ( 1,837 )

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 — — — 103 — — 103 — 103

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Dividends declared on common stock — — — — ( 302 ) — ( 302 ) — ( 302 )

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)

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

Dividends declared on preferred stock — — — — ( 151 ) — ( 151 ) — ( 151 )

Change in accumulated other comprehensive income (loss) — — — — — 23 23 — 23

Other — — — 1 1 — 2 ( 2 ) —

December 31, 2022

$ 2,000 $ 5 $ ( 3,395 ) $ 9,928 $ ( 3,643 ) $ 7 $ 4,902 $ 16 $ 4,918

See Notes to the Consolidated Financial Statements.

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

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

See Note 19 for further information concerning our reportable business segments.

Winter Storm Uri

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Winter Storm Uri had a material adverse impact on our 2021 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.

Uplift Securitization Proceeds 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 the U.S.

Government declared the COVID-19 outbreak a national emergency.

government has deemed electricity generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency.

As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers.

Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations.

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 years ended December 31, 2021 and 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.

In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we received $ 544 million of proceeds from ERCOT in the second quarter of 2022.

The Company accounted for the proceeds we received 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.

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 final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event (see Note 12).

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.

Dividends Declared — In February 2023, the Board declared a quarterly dividend of $ 0.1975 per share of common stock that will be paid in March 2023.

In February 2023, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2023.

Basis of Presentation

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Goodwill and Intangible Assets with Indefinite Lives

As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill.

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist.

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Defined Benefit Pension Plans and OPEB Plans

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

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

Pension benefits are offered to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula.

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

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.

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 $ 54 million, zero and zero and a corresponding increase in the deferred tax assets in 2022, 2021 and 2020, respectively.

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

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Property, Plant and Equipment

Property, plant and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed (see Notes 2 and 3).

Significant improvements or additions to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred.

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(EEI) that we do not own.

EEI is our consolidated subsidiary that owns a coal facility in Joppa, Illinois.

EEI is our consolidated subsidiary that owns a coal facility in Joppa, Illinois that was retired September 1, 2022 (see Note 3).

This noncontrolling interest is classified as a component of equity separate from stockholders' equity in the consolidated balance sheets.

1 unchanged sentence

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capital.

Treasury stock purchases made by third party brokers on our behalf are recorded on a trade date basis when we are contractually obligated to pay the broker for their repurchase costs.

At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration.

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We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.

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 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.

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

Facilitation of the Effects of Reference Rate Reform on Financial Reporting — In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting .

The ASU provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued.

The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022.

The adoption of this guidance did not have a material impact on our financial statements.

In March 2020, the SEC amended Rule 3-10 of Regulation S-X regarding financial disclosure requirements for registered debt offerings involving subsidiaries as either issuers or guarantors and affiliates whose securities are pledged as collateral.

This new guidance narrows the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamlines the alternative disclosures required in lieu of those statements.

This rule is effective January 4, 2021 with earlier adoption permitted.

We elected to adopt this rule in the first quarter of 2020.

Accordingly, summarized financial information has been presented only for the issuer and guarantors of the Company's registered debt securities, and the location of the required disclosures has been moved outside the Notes to the Consolidated Financial Statements and is provided in Part II, Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations under Financial Condition — Guarantor Summary Financial Information .

In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) — Amendments to SEC Paragraphs Pursuant to SEC Release No.

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

ACQUISITIONS AND BUSINESS COMBINATION ACCOUNTING

Ambit Transaction

On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra, completed the Ambit Transaction.

Ambit is an energy retailer selling both electricity and natural gas products to residential and small business customers in 16 states.

Vistra funded the purchase price of $ 555 million (including cash acquired and net working capital) using cash on hand.

All of Ambit's outstanding debt was repaid from the purchase price at closing and not assumed by Vistra.

Crius Transaction

On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C.

Ltd., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius.

Crius is an energy retailer selling both electricity and natural gas products to residential and small business customers in 19 states.

Vistra funded the purchase price of $ 400 million (including $ 382 million for outstanding trust units) using cash on hand.

In addition, Vistra assumed $ 140 million of outstanding debt and acquired $ 26 million of cash at the closing of the Crius Transaction.

See Note 11 for discussion of debt assumed in the Crius Transaction.

Ambit and Crius Business Combination Accounting

We believe the Ambit Transaction has (i) augmented Vistra's existing retail marketing capabilities with additional direct selling capability and a proprietary technology platform, (ii) reduced risk and aided expansion into higher margin channels by improving Vistra's match of its generation to load profile due to a high degree of overlap of Vistra's generation fleet with Ambit's approximately 11 TWh of annual load, primarily in ERCOT and PJM and (iii) enhanced the integrated value proposition through collateral and transaction efficiencies, particularly via Ambit's retail electric portfolio.

We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving Vistra's match of its generation to load profile due to a high degree of overlap of Vistra's generation fleet with Crius' approximately 10 TWh of annual electricity load, (ii) established a platform for growth by leveraging Vistra's existing retail marketing capabilities and Crius' experienced team and (iii) enhanced the integrated value proposition through collateral and transaction efficiencies, particularly via Crius' retail electric portfolio.

Each of the Ambit Transaction and Crius Transaction, respectively, 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 Ambit Acquisition Date and Crius Acquisition Date, respectively.

The combined results of operations are reported in our consolidated financial statements beginning as of the respective Ambit Acquisition Date and Crius Acquisition 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 derivatives were valued using the methods described in Note 15 (Level 2 or Level 3).

• Acquired retail customer relationship was valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).

• Crius' long-term debt was valued using a market approach (Level 2).

The following table summarizes the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Ambit Transaction and Crius Transaction, respectively, as of the Ambit Acquisition Date and Crius Acquisition Date, respectively.

The Ambit Transaction purchase price was $ 555 million (including cash acquired and net working capital) and the Crius Transaction purchase price was $ 400 million.

The final purchase price allocations were completed in the second quarter of 2020 for the Crius Transaction and the third quarter of 2020 for the Ambit Transaction.

Ambit Transaction and Crius Transactions Final Purchase Price Allocations

Ambit Transaction Crius Transaction

Purchase Price

Allocation Measurement Period Adjustments recorded Final

Purchase Price

Allocation Measurement Period Adjustments recorded

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

Net working capital 32 3 ( 9 ) ( 42 )

Accumulated deferred income taxes — — — ( 36 )

Identifiable intangible assets 218 ( 45 ) 317 23

Goodwill 258 44 243 38

Commodity and other derivative contractual assets 23 — 18 —

Other noncurrent assets 13 — 17 ( 3 )

Total assets acquired 593 2 612 ( 20 )

Identifiable intangible liabilities — — 2 ( 34 )

Long-term debt, including amounts due currently — — 140 —

Commodity and other derivative contractual liabilities 28 — 40 —

Accumulated deferred income taxes — — 14 14

Other noncurrent liabilities and deferred credits 10 2 16 —

Total liabilities assumed 38 2 212 ( 20 )

Identifiable net assets acquired $ 555 $ — $ 400 $ —

Acquisition costs incurred in the Ambit Transaction and Crius Transaction totaled $ 1 million and $ 2 million, respectively.

For the Ambit Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the Ambit Transaction totaling $ 193 million and $ 2 million, respectively.

For the Crius Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the Crius Transaction totaling $ 453 million and zero , respectively.

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 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.

Ambit Transaction Crius Transaction

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

Revenues $ 12,931 $ 12,373

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.

The amendments in the ASU were effective for all entities as of March 12, 2020 through December 31, 2022.

In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848):

Deferral of the Sunset Date of Topic 848 , which deferred the sunset date of Topic 848 from December 31, 2022 to December 31, 2024.

The expedients and exceptions may be elected over time as reference rate reform activities occur through the sunset date.

We have applied the optional expedients to amendments to financial instruments that now reference the Secured Overnight Financing Rate (SOFR).

Additionally, we have identified the financial instruments to which the expedients could be applied, if deemed necessary, as amendments to these financial instruments are made through the sunset date.

DEVELOPMENT OF GENERATION FACILITIES

Texas Segment Solar Generation and Energy Storage Projects

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.

In September 2020, we announced the planned development of up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas.

Of this planned development in Texas, 158 MW of solar generation came online in January and February 2022 and the battery ESS came online in April 2022.

Estimated commercial operation dates for the remaining facilities to be developed are expected to be 2024 and beyond, but we will only invest in growth projects if we are confident in the expected returns.

As of December 31, 2022, we had accumulated approximately $ 44 million in construction-work-in-process for these remaining Texas segment solar generation projects.

East Segment Solar Generation and Energy Storage Projects

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Estimated commercial operation dates for these facilities range from 2024 to 2025.

As of December 31, 2022, we had accumulated approximately $ 14 million in construction-work-in-process for these East segment solar generation and battery ESS projects.

West Segment Energy Storage Projects

Oakland — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California.

Oakland — In June 2019, East Bay Community Energy (EBCE) signed a 10 -year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California.

In April 2020, the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E).

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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.

The CPUC approved the resource adequacy contract in November 2018.

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.

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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.

The CPUC approved the resource adequacy contract in August 2020.

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.

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

The CPUC approved the resource adequacy and energy settlement contract in April 2022.

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

As of December 31, 2022, we had accumulated approximately $ 288 million in construction-work-in-process for Moss Landing Phase III.

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.

A review found the root cause originated in systems separate from the battery system.

The facility was offline as we performed the work necessary to return the facility to service.

Restoration work on the facility was completed in June 2022.

Moss Landing Phases II and III were 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.

A review found the root cause originated in systems separate from the battery system.

The facility was offline as we performed the work necessary to return the facility to service.

Restoration work on the facility was completed in September 2022.

Moss Landing Phases I and III were not affected by this incident.

These incidents did not have a material impact on our results of operations.

RETIREMENT OF GENERATION FACILITIES

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)

Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2025

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

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

Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027

Newton Newton, IL MISO/PJM Coal 615 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.

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.

As part of the settlement, which was approved by the U.S.

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 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.

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

Duck Creek Canton, IL MISO Coal 425 December 15, 2019

Havana Havana, IL MISO Coal 434 November 1, 2019

Hennepin Hennepin, IL MISO Coal 294 November 1, 2019

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.

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 our consolidated statements of operations.

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.

Operational results for plants with defined retirement dates are included in our Sunset segment beginning in the quarter when a retirement plan is announced and move to the Asset Closure segment at the beginning of the calendar year the retirement is expected to occur.

Retirement date represents the first full day in which a plant does not operate.

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

Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2025 Sunset

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

Edwards Bartonville, IL MISO Coal 585 Retired January 1, 2023 Sunset

Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure

Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure

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

Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027 Sunset

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

Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure

(a) Generation facilities may retire earlier than the end of 2027 if economic or other conditions dictate.

In 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 12), and in furtherance of our efforts to significantly reduce our carbon footprint.

Expected plant retirement expenses of $ 31 million and $ 12 million, respectively, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our Sunset and Asset Closure segments, respectively.

As previously announced in April 2021, we retired the Joppa generation facilities in September 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018.

As previously announced in July 2021, we retired the Zimmer coal generation facility in June 2022 due to the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.

See Note 20 for discussion of impairments recorded in connection with these determinations.

The following tables disaggregate our revenue by major source:

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

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.

The East segment includes $ 302 million of capacity sold offset by $ 282 million of capacity purchased.

The Sunset segment includes $ 66 million of capacity sold offset by $ 3 million of capacity purchased.

The Asset Closure segment includes $ 20 million of capacity sold.

(b) Includes $ 2.163 billion of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $ 544 million due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term.

See Note 19 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.

(c) Texas and East segments include $ 817 million and $ 38 million, respectively, of affiliated unrealized net losses, and Sunset segment includes $ 34 million of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2021

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Hedging and other revenues (b) ( 115 ) ( 4,355 ) 123 35 ( 1,043 ) ( 328 ) — ( 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 ( 835 ) ( 328 ) ( 2,284 ) ( 5,623 )

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

The West segment includes $ 1 million of capacity sold.

The Sunset segment includes $ 142 million of capacity sold offset by $ 4 million of capacity purchased.

The Asset Closure segment includes $ 46 million of capacity sold.

(b) Includes $ 1.191 billion of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $ 298 million due to the discontinuance of NPNS accounting on a retail electric contract portfolio in the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term.

See Note 19 for unrealized net gains (losses) by segment.

(c) Texas, East and Sunset segments include $ 1.028 billion, $ 529 million and $ 162 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2020

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

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

The Sunset segment includes $ 128 million of capacity sold offset by $ 3 million of capacity purchased.

The Asset Closure segment includes $ 39 million of capacity sold.

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

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Some of our contracts for the sale of electricity meet the definition of a derivative under the accounting standards related to derivative instruments.

Revenue from derivative contracts is not considered revenue from contracts with customers under the accounting standards related to revenue.

Revenue from derivative contracts accounted for under ASC 815, Derivatives and Hedging is not considered revenue from contracts with customers under the accounting standards related to revenue.

Our revenue from the sale of electricity under derivative contracts, including the impact of unrealized gains or losses on those contracts, is reported in the table above as hedging and other revenues.

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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 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.

The deferred acquisition and contract cost balance as of December 31, 2022 and 2021 was $ 89 million and $ 80 million, respectively.

The amortization related to these costs during the years ended December 31, 2022, 2021 and 2020 totaled $ 83 million, $ 75 million and $ 46 million respectively, recorded as SG&A expenses, and $ 6 million, $ 6 million and $ 7 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.

Practical Expedients

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Balance at December 31, 2019 $ 2,553

Measurement period adjustments recorded in connection with the Merger 14

Goodwill recorded in connection with the Crius Transaction 257

Goodwill recorded in connection with the Ambit Transaction 214

Balance at December 31, 2019 2,553

Measurement period adjustments recorded in connection with the Crius Transaction ( 14 )

Measurement period adjustments recorded in connection with the Ambit Transaction 44

Measurement period adjustments recorded in 2020 in connection with the Crius Transaction ( 14 )

Measurement period adjustments recorded in 2020 in connection with the Ambit Transaction 44

Balance at December 31, 2022, 2021 and 2020 $ 2,583

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The goodwill related to the Ambit Transaction is deductible for tax purposes over 15 years on a straight-line basis.

Goodwill and intangible assets with indefinite useful lives are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist.

Goodwill is required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist.

We have selected October 1 as our annual goodwill test date.

On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2022.

Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition and changes in reporting unit book value.

Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates and changes in reporting unit book value.

Identifiable Intangible Assets and Liabilities

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

Mineral interests (not currently subject to amortization) — 1

Total identifiable intangible assets $ 1,958 $ 2,146

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Other identifiable intangible assets Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization 4 391 279 223

Total intangible asset expense (a) $ 494 $ 596 $ 507

Total intangible asset expense, net (a) $ 604 $ 494 $ 596

(a) Amounts recorded in depreciation and amortization totaled $ 208 million, $ 275 million and $ 360 million for the years ended December 31, 2022, 2021 and 2020, respectively.

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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.

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

We have selected October 1 as our test date.

Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest 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, 2022.

• 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.

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The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts.

• Contractual service agreements — Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements, rail transportation agreements and rail car leases, and are being amortized based on the expected usage of the service agreements over the contract terms.

• Contractual service agreements — Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are being amortized based on the expected usage of the service agreements over the contract terms.

The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment.

Amortization of rail transportation and rail car lease agreements is recorded to fuel, purchased power costs and delivery fees.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

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Nondeductible compensation 5 4 —

Nondeductible transaction costs — — 2

Equity awards ( 3 ) 1 —

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Lignite depletion ( 4 ) ( 3 ) ( 3 )

Texas gross margin amended return — — ( 3 )

Other 8 3 ( 6 )

Income tax expense (benefit) $ ( 350 ) $ ( 458 ) $ 266

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Net Deferred Income Tax Asset $ 1,709 $ 1,302

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.

As of December 31, 2022, we had total net deferred tax assets of approximately $ 1.709 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, 2022, we recognized a tax benefit of $ 9 million on the release of state valuation allowances.

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.

As of December 31, 2022, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets.

We have identified negative evidence, in the form of cumulative losses on an unadjusted basis over the preceding 12 quarters.

We evaluated historical earnings after adjusting for certain nonrecurring items for purposes of projecting future income, performed scheduling of the reversal of temporary differences, and considered other positive and negative evidence.

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.

A valuation allowance of approximately $ 3 million was recorded in the fourth quarter of 2022 against a portion of our charitable contribution deferred tax asset that is not more likely than not to be utilized before expiration in 2024.

As of December 31, 2022, 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.

The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax liabilities of $ 7 million and $ 9 million at December 31, 2022 and 2021, respectively.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear production tax credit (PTC), a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15 % corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1 % excise tax on net stock repurchases.

Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months.

Vistra is not subject to the CAMT in the next fiscal year since it applies only to corporations that have a three-year average annual adjusted financial statement income in excess of $ 1 billion.

The excise tax is not expected to have a material impact on our financial statements.

As of December 31, 2022, we have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect and for estimating the TRA liability.

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

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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.

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.

As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the addback of depreciation and amortization to adjusted taxable income.

As a result, under the law as currently enacted, Vistra's deductible business interest expense will be significantly limited for the 2022 tax year.

Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the addback of depreciation and amortization to adjusted taxable income.

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

We paid the remainder of the previously deferred taxes in December 2022.

Liability for Uncertain Tax Positions

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Reductions based on tax positions related to prior years ( 1 ) — ( 90 )

Additions based on tax positions related to the current year — — 87

Settlements with taxing authorities ( 1 ) ( 2 ) —

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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 totaled $ 38 million at December 31, 2021.

In the second quarter of 2022, the employment tax audit for tax year 2018 was closed with no adjustment.

The federal income tax audit is in its final stages and Vistra expects final closing on an agreed basis with immaterial changes in the first half of 2023.

It is reasonably possible $ 36 million of the uncertain tax positions could be resolved within the next 12 months upon final closing.

In December 2022, the IRS formally concluded the federal income tax examination of Crius Energy Corp's pre-acquisition tax years 2015 and 2016, with payment of the agreed adjustments of less than $ 1 million made in 2022.

All adjustments were agreed, closing out tax years 2015 and 2016.

Uncertain tax positions totaled $ 36 million and $ 38 million as of December 31, 2022 and 2021, respectively.

Of the amounts recorded as unrecognized tax benefits, an insignificant portion would impact our effective tax rate if recognized.

Tax Matters Agreement

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TAX RECEIVABLE AGREEMENT OBLIGATION

On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first-lien creditors of TCEH.

On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH.

The TRA generally provides for the payment by us to holders of TRA Rights of 85 % of the amount of cash savings, if any, in U.S.

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Noncurrent TRA obligation at the end of the period $ 514 $ 394 $ 447

(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.

(a) During the year ended December 31, 2022, we recorded an increase to the carrying value of the TRA obligation totaling $ 64 million as a result of adjustments to forecasted book and taxable income due to increases in commodity price forecasts.

During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling approximately $ 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 $ 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.

As of December 31, 2022, the estimated carrying value of the TRA obligation totaled $ 522 million, which represents the discounted amount of projected payments under the TRA.

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Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation.

The TRA provides that, in the event that Vistra breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions.

EARNINGS PER SHARE

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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.

The Receivables Facility was renewed in July 2022, extending the term of the Receivables Facility to July 2023, adjusting the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during certain periods to align with the peak retail season which increased the commitments by $ 25 million for the settlement periods through December 2022 as compared to prior periods, as follows:

(i) $ 625 million beginning with the settlement date in July 2022 until the settlement date in August 2022, (ii) $ 750 million from the settlement date in August 2022 until the settlement date in November 2022, (iii) $ 625 million from the settlement date in November 2022 until the settlement date in December 2022, and (iv) $ 600 million from the settlement date in December 2022 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.

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

As of December 31, 2022, outstanding borrowings under the Receivables Facility totaled $ 425 million and were supported by $ 1.013 billion 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.

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).

TXU Energy and the other originators under the Receivables Facility have a 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.

In August 2022, the Repurchase Facility was renewed until July 2023 while maintaining the facility size of $ 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.

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TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility.

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

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

LONG-TERM DEBT

Amounts in the table below represent the categories of long-term debt obligations incurred by the Company.

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

There were no outstanding borrowings under the Repurchase Facility as of both December 31, 2022 and December 31, 2021.

Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company.

Vistra Operations Credit Facilities $ 2,514 $ 2,543

Vistra Operations Senior Secured Notes:

4.875 % Senior Secured Notes, due May 13, 2024

3.550 % Senior Secured Notes, due July 15, 2024

5.125 % Senior Secured Notes, due May 13, 2025

3.700 % Senior Secured Notes, due January 30, 2027

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Equipment Financing Agreements 79 92

8.82 % Building Financing due semiannually through February 11, 2022 (a)

Total other long-term debt 79 311

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Total long-term debt less amounts due currently $ 11,933 $ 10,477

(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 current assets in our consolidated balance sheets.

Vistra Operations Credit Facilities

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).

As of December 31, 2022 and 2021, outstanding short-term borrowings totaled $ 650 million and zero , respectively, under the Commodity-Linked Facility and the Revolving Credit Facility (described below).

Vistra Operations Credit Facilities and Commodity-Linked Revolving Credit Facility

Vistra Operations Credit Facilities — As of December 31, 2022, the Vistra Operations Credit Facilities consisted of up to $ 5.889 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $ 3.375 billion (Revolving Credit Facility) and term loans of $ 2.514 billion (Term Loan B-3 Facility).

These amounts reflect the following transactions and amendments completed in 2022, 2021 and 2020:

• On April 29, 2022 (April 2022 Amendment Effective Date) and July 18, 2022 (July 2022 Amendment Effective Date), Vistra Operations entered into amendments (Credit Agreement Amendments) to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Island Branch, as administrative agent and collateral agent, and the other parties named therein.

Pursuant to the Credit Agreement Amendments, new classes of extended revolving credit commitments maturing in April 2027 were established in aggregate amounts of $ 2.8 billion and $ 725 million as of the April 2022 Amendment Effective Date and the July 2022 Amendment Effective Date, respectively.

The July 18, 2022 amendment to the Vistra Operations Credit Agreement also provides that Vistra Operations will terminate at least $ 350 million in Extended Revolving Credit Facility commitments by December 30, 2022 or earlier if Vistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity of Vistra Operations and its guarantors.

In accordance with this requirement, effective December 30, 2022, Vistra Operations terminated $ 350 million in revolving commitments.

After giving effect to the Credit Agreement Amendments and the revolving commitment reduction, the aggregate amount of revolving commitments maturing on April 29, 2027 equals $ 3.175 billion (Extended Revolving Credit Facility), while the $ 200 million in revolving commitments maturing on June 14, 2023 (Non-Extended Revolving Credit Facility) remain unchanged by the Credit Agreement Amendments.

Furthermore, the Credit Agreement Amendments appointed new revolving letter of credit issuers, such that the aggregate amount of revolving letter of credit commitments equals $ 3.245 billion after giving effect to the Credit Agreement Amendments.

Fees and expenses related to the Credit Agreement Amendments totaled $ 8 million in the year ended December 31, 2022, which were capitalized as a reduction in the carrying amount of the debt.

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

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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.

Borrowings under the Term Loan A Facility were reported in short-term borrowings in our 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 $ 1.25 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.

We recorded an extinguishment loss of $ 1 million on the transaction in the year ended December 31, 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.

• In November 2019, Vistra Operations used the net proceeds from the November 2019 Senior Secured Notes Offering described below and $ 799 million of incremental borrowings under the Term Loan B-3 Facility to repay the entire amount outstanding of $ 1.897 billion of term loans under the B-1 Facility (Term Loan B-1 Facility).

Fees and expenses related to the transactions totaled $ 2 million in the year ended December 31, 2019, which were recorded as interest expense and other charges on the consolidated statements of operations.

• In October 2019, Vistra Operations borrowed $ 550 million under the Revolving Credit Facility.

The proceeds of the borrowings were used for general corporate purposes, including the funding of a $ 425 million dividend to Vistra to pay the principal, premium and interest due in connection with the redemption by Vistra of the entire $ 387 million aggregate principal amount outstanding of 7.625 % senior notes described below.

In November 2019, Vistra Operations repaid $ 200 million under the Revolving Credit Facility.

• In June 2019, Vistra Operations used the net proceeds from the June 2019 Senior Secured Notes Offerings (described below) to repay $ 889 million under the Term Loan B-1 Facility, the entire amount outstanding of $ 977 million of term loans under the B-2 Facility (Term Loan B-2 Facility, and together with the Term Loan B-1 Facility and the Term Loan B-3 Facility, the Term Loan B Facility) and $ 134 million under the Term Loan B-3 Facility.

We recorded an extinguishment loss of $ 4 million on the transactions in the year ended December 31, 2019.

• In March 2019 and May 2019, the Vistra Operations Credit Facilities were amended whereby we obtained $ 225 million of incremental Revolving Credit Facility commitments.

The letter of credit sub-facility was also increased by $ 50 million.

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.

During the year ended December 31, 2022, we borrowed $ 1.75 billion and repaid $ 1.5 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes.

The Vistra Operations Credit Facilities and related available capacity at December 31, 2021 are presented below.

Our credit facilities and related available capacity at December 31, 2022 are presented below.

December 31, 2022

Vistra Operations Credit Facilities Maturity Date Facility

Credit Facilities Maturity Date Facility

Borrowings Letters of Credit Outstanding Available

Revolving Credit Facility (a) June 14, 2023 $ 2,725 $ — $ 1,471 $ 1,254

Term Loan B-3 Facility (b) December 31, 2025 2,543 2,543 —

Extended Revolving Credit Facility (a) April 29, 2027 $ 3,175 $ 237 $ 1,777 $ 1,161

Non-Extended Revolving Credit Facility (b) June 14, 2023 $ 200 $ 13 $ 112 $ 75

Term Loan B-3 Facility (c) December 31, 2025 2,514 2,514 — —

Total Vistra Operations Credit Facilities $ 5,889 $ 2,764 $ 1,889 $ 1,236

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

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

Letters of credit outstanding reduce our available capacity.

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

(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.

Commodity-Linked Facility (d) October 4, 2023 1,350 400 — 808

Total Credit Facilities $ 7,239 $ 3,164 $ 1,889 $ 2,044

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

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

The full amount of Extended Revolving Credit Facility available capacity can be utilized to issue letters of credit.

In December 2022, Vistra Operations terminated $ 350 million in Extended Revolving Credit Facility commitments.

(b) Non-Extended Revolving Credit Facility used for general corporate purposes.

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

The full amount of Non-Extended Revolving Credit Facility available capacity can be utilized to issue letters of credit.

(c) 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.

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 %.

(d) Commodity-Linked Facility (defined below) used to support our comprehensive hedging strategy.

As of December 31, 2022, the borrowing base of $ 1.208 billion is lower than the facility limit which represents aggregate commitments of $ 1.35 billion.

See Commodity-Linked Revolving Credit Facility below for discussion of the borrowing base calculation.

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

Under the Vistra Operations Credit Agreement, the interest applicable to the Extended Revolving Credit Facility is based on a term Secured Overnight Financing Rate (SOFR), plus a spread that will range from 1.25 % to 2.00 %, based on the ratings of Vistra Operations' senior secured long-term debt securities, and the fee on any undrawn amounts with respect to the Extended Revolving Credit Facility had been revised to range from 17.5 basis points to 35.0 basis points, based on ratings of Vistra Operations' senior secured long-term debt securities.

As of December 31, 2022, there were $ 237 million outstanding borrowings under the Extended Revolving Credit Facility and the weighted average interest rate on outstanding borrowings was 8.25 % based on the Alternate Bank Rate (ABR) plus a spread of 0.75% as required to be used for same-day borrowings.

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

The applicable interest rate margins for the Extended Revolving Credit Facility and the fee for undrawn amounts relating to such extended commitments may further be adjusted from time to time dependent upon the Company's performance relative to certain sustainability-linked targets and thresholds.

Under the Vistra Operations Credit Agreement, cash borrowings under the Non-Extended Revolving Credit Facility bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75 %.

As of December 31, 2022, there were $ 13 million outstanding borrowings under the Non-Extended Revolving Credit Facility and the weighted average interest rate on outstanding borrowings was 8.25 % based on the ABR plus a spread of 0.75% as required to be used for same-day borrowings.

Letters of credit issued under the Non-Extended 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 %.

As of December 31, 2022, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 6.13 % 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.

Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra Operations Credit Facilities.

The Vistra Operations Credit Agreement includes certain collateral suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two ratings agencies, there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then outstanding (or the holders thereof agreeing to release such security interests), and there being no outstanding revolving credit commitments the maturities of which have not been extended to April 29, 2027 (or the holders thereof agreeing to release such security interests), such collateral suspension provisions would continue to be in effect unless and until Vistra Operations no longer holds unsecured investment grade ratings from at least two ratings agencies, at which point collateral reversion provisions would take effect (subject to a 60 -day grace period).

The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations Credit Facilities.

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The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations.

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.

As of December 31, 2022, 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.

Commodity-Linked Revolving Credit Facility — In order to support our comprehensive hedging strategy, in February 2022, Vistra Operations entered into a $ 1.0 billion senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) 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.

In May 2022, we entered into an amendment to the Commodity-Linked Facility to increase the aggregate available commitments from $ 1.0 billion to $ 2.0 billion and to provide the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility by an additional $ 1.0 billion to a facility size of $ 3.0 billion.

Subsequent amendments in May 2022 and June 2022 increased the aggregate available commitments from $ 2.0 billion to $ 2.25 billion.

In October 2022, Vistra initiated amendments to the Commodity-Linked Facility to, among other things, (i) extend the maturity date to October 4, 2023 and (ii) reduce the aggregate available commitments to $ 1.35 billion.

Fees and expenses related to the facility totaled $ 6 million in the year ended December 31, 2022, which were capitalized as a reduction in the carrying amount of the debt.

The Vistra Operations Commodity-Linked Credit Agreement includes a covenant, solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings exceeds 30 % of the revolving commitments), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, not to exceed 5.50 to 1.00).

Although the period ended December 31, 2022 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.

Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments 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.

Vistra Operations intends to use any borrowings 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.

Interest Rate Swaps — Vistra employs interest rate swaps to hedge our exposure to variable rate debt.

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Swapped to variable $ 700 July 2023 3.20 % - 3.23 %

Swapped to fixed (a) $ 720 February 2024 3.71 % - 3.72 %

Swapped to fixed $ 720 February 2024 3.71 % - 3.72 %

Swapped to variable $ 720 February 2024 3.20 % - 3.20 %

Swapped to fixed (b) $ 3,000 July 2026 4.72 % - 4.79 %

Swapped to variable (b) $ 700 July 2026 3.28 % - 3.33 %

(a) In June 2018, we completed the novation of $ 1.959 billion of Vistra (legacy Dynegy) interest rate swaps to Vistra Operations, of which $ 398 million expired and $ 841 million were terminated in June 2019.

(b) Effective from July 2023 through July 2026.

Swapped to fixed (a) $ 3,000 July 2026 4.72 % - 4.79 %

Swapped to variable (a) $ 700 July 2026 3.28 % - 3.33 %

(a) Effective from July 2023 through July 2026.

During 2019, Vistra entered into $ 2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate.

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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.

Secured Letter of Credit Facilities

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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.

In October 2021, September 2022 and October 2022, Vistra entered into additional Secured LOC Facilities which are used for general corporate purposes.

As of December 31, 2022, $ 762 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 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 matured in December 2021.

Each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, not to exceed 5.50 to 1.00).

As of December 31, 2022, we were in compliance with these financial covenants.

Vistra Operations Senior Secured Notes

In 2019, Vistra Operations issued and sold $ 3.1 billion aggregate principal amount of senior secured notes (June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes) in offerings (the June 2019 Senior Secured Notes Offering and the November 2019 Senior Secured Notes Offering) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the following:

Senior Secured Notes Maturity Year Interest Terms

(Due Semiannually in Arrears) June 2019

Senior Secured Notes Offering (a) November 2019 Senior Secured Notes Offering (b)

3.550 % Senior Secured Notes

2024 January 15 and July 15 $ 1,200 $ 300

3.700 % Senior Secured Notes

2027 January 30 and July 30 — 800

4.300 % Senior Secured Notes

2029 January 15 and July 15 800 —

Total senior secured notes $ 2,000 $ 1,100

Net proceeds $ 1,976 $ 1,099

Debt issuance and other fees (c) $ 20 $ 10

(a) The June 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers.

Net proceeds, together with cash on hand, were used to prepay certain amounts outstanding and accrued interest (together with fees and expenses) under the Term Loan B Facility.

(b) The November 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and J.P.

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

Net proceeds, together with borrowings under the Term Loan B-3 Facility and cash on hand, were used to repay the entire amount outstanding and accrued interest (together with fees and expenses) under the Term Loan B-1 Facility.

The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes (collectively, the Senior Secured Notes) provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities.

In May 2022, Vistra Operations issued $ 1.5 billion aggregate principal amount of senior secured notes (2022 Senior Secured Notes), consisting of $ 400 million aggregate principal amount of 4.875 % senior secured notes due 2024 ( 4.875 % Senior Secured Notes) and $ 1.1 billion aggregate principal amount of 5.125 % senior secured notes due 2025 ( 5.125 % Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (Senior Secured Notes Offering).

The 2022 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers.

The 4.875 % Senior Secured Notes mature in May 2024 and the 5.125 % Senior Secured Notes mature in May 2025.

Interest on the 2022 Senior Secured Notes is payable in cash semiannually in arrears on May 13 and November 13 of each year, beginning in November 2022.

Net proceeds from the Senior Secured Notes Offering totaling $ 1.485 billion, together with cash on hand, were used to pay down borrowings under the Commodity-Linked Facility.

Fees and expenses related to the offering totaled $ 17 million in the year ended December 31, 2022, which were capitalized as a reduction in the carrying amount of the debt.

Since 2019, Vistra Operations issued and sold $ 4.6 billion aggregate principal amount of senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the 3.550 % senior secured notes due 2024, the 3.700 % senior secured notes due 2027, the 4.300 % senior secured notes due 2029 and the 2022 Senior Secured Notes (collectively, as each may be amended or supplemented from time to time, the Senior Secured Notes) provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities.

The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities, which consists of a substantial portion of the property, assets and rights owned by Vistra Operations and certain direct and indirect subsidiaries of Vistra Operations as subsidiary guarantors (collectively, the Guarantor Subsidiaries) as well as the stock of Vistra Operations held by Vistra Intermediate.

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Vistra Operations Senior Unsecured Notes

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) 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

2027 February 15 and August 15 1,300 — —

5.000 % Senior Unsecured Notes

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

Net Proceeds $ 1,287 $ 1,287 $ 1,235

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

(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).

(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.

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 June 2019 Tender Offer (defined below) and (ii) the redemption of approximately $ 306 million of our outstanding 7.375 % senior notes and approximately $ 87 million of our 7.625 % senior unsecured notes due 2024 ( 7.625 % senior notes) in July 2019.

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.

In May 2021, Vistra Operations issued and sold $ 1.25 billion aggregate principal amount of 4.375 % senior unsecured notes due 2029 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

The 4.375 % senior unsecured notes due 2029 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 4.375 % senior unsecured notes mature in May 2029, with interest payable in arrears on May 1 and November 1 beginning November 1, 2021 with interest accrued from May 10, 2021.

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

Fees and expenses were capitalized as a reduction in the carrying amount of the debt.

Since 2018, Vistra Operations has issued and sold $ 4.85 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 indentures governing the 5.500 % senior unsecured notes due 2026, the 5.625 % senior unsecured notes due 2027, the 5.000 % senior unsecured notes due 2027 and the 4.375 % senior unsecured notes due 2029 (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 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.

Through December 31, 2021, approximately $ 666 million had been repurchased under the $ 1.0 billion April 2020 authorization, consisting of the redemption of the Vistra 5.875 % senior unsecured notes due 2023 ( 5.875 % senior notes) and the redemption of the Vistra 8.125 % senior unsecured notes due 2026 ( 8.125 % senior notes), each as described below.

In March 2021, the Board authorized up to $ 1.8 billion to voluntarily repay or repurchase outstanding debt, which authorization expired in March 2022 (the Prior Authorization).

No amounts were repurchased under the Prior Authorization.

In October 2022, the Board re-authorized the voluntary repayment or repurchase of up to $ 1.8 billion of outstanding debt, with such authorization expiring on December 31, 2023 (Current Authorization).

Through December 31, 2022, no amounts were repurchased under the Current Authorization.

Vistra Senior Unsecured Notes

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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.

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

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.

Extinguishment gains of $ 11 million were recognized on the transactions in the year ended December 31, 2020.

Vistra had no outstanding senior notes at the Parent level as of December 31, 2022 and 2021.

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

6.750 %Senior Unsecured Notes

2019 $ — $ — $ — $ —

7.375 % Senior Unsecured Notes

2022 1,193 173 341 —

5.875 % Senior Unsecured Notes

2023 — — — 500

7.625 % Senior Unsecured Notes

2024 — 672 475 —

8.034 % Senior Unsecured Notes

2024 — — 25 —

8.000 % Senior Unsecured Notes

2025 — — — 81

8.125 %Senior Unsecured Notes

2026 — — — 166

Total $ 1,193 $ 845 $ 841 $ 747

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

(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.

(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.

(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.

Other Long-Term Debt

Amortizing Notes — On the Merger Date, Vistra assumed the obligations of Dynegy's senior unsecured amortizing note (Amortizing Notes) that matured on July 1, 2019.

The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 14).

Each installment payment per Amortizing Note was paid in cash and constituted a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00 %.

Interest was calculated on the basis of a 360-day year consisting of twelve 30-day months.

Payments were applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the indenture (Amortizing Notes Indenture).

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 — 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 a debt issuance with an implied interest rate of approximately 4.25 %.

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

In May 2022, the final capacity payment from PJM during the Planning Years 2021-2022 was paid, and the terms of the 2021-2022 Forward Capacity were fulfilled.

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.

Mandatorily Redeemable Subsidiary Preferred Stock — In October 2019, PrefCo voluntarily redeemed the entire $ 70 million aggregate principal amount outstanding of its authorized preferred stock at a price per share equal to the preferred liquidation amount, plus accrued and unpaid dividends to and including the date of redemption.

Debt Assumed in Crius Transaction — On the Crius Acquisition Date, Vistra assumed $ 140 million in long-term debt obligations in connection with the Crius Transaction consisting of the following:

• $ 44 million of 9.5 % promissory notes due July 2025 (2025 promissory notes);

• $ 8 million of 2 % Connecticut Department of Economic and Community Development (CT DECD) term loans due February 2027;

• $ 88 million of borrowings and $ 9 million of issued letters of credit under the legacy Crius credit facility.

In July 2019, borrowings of $ 88 million under the legacy Crius credit facility were repaid using cash on hand.

In November 2019, (i) borrowings of approximately $ 38 million under the 2025 promissory notes were repaid using cash on hand and (ii) borrowings of approximately $ 2 million were offset by legacy indemnification obligations of the holders of the 2025 promissory notes.

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

Long-term debt maturities at December 31, 2022 are as follows:

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Contractual Commitments

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.

As of December 31, 2022, we had minimum contractual commitments under long-term service and maintenance contracts, energy-related contracts and other agreements as follows:

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

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As of December 31, 2022, termination costs of $ 65 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.

Expenditures under our coal purchase and coal transportation agreements totaled $ 995 million, $ 850 million, and $ 845 million for the years ended December 31, 2022, 2021 and 2020, respectively.

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

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Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.

Gas Index Pricing Litigation — We, through our subsidiaries, and other companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002.

Gas Index Pricing Litigation — We, through our subsidiaries, and other companies have been named as defendants in lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002.

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.

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.

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.

In November 2019, IPH and IPRG sent suspension notices to the railroads asserting that the MPS rule requirement to retire at least 2,000 megawatts of generation (see discussion below) was a change-in-law under the agreement that rendered continued operation of the plants no longer economically feasible.

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.

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.

We now remain as a defendant in only one action, which is a consolidated putative class action lawsuit pending in federal court in Wisconsin where a class has been certified and an interlocutory appeal will be heard in the U.S.

Court of Appeals for the Seventh Circuit (Seventh Circuit Court).

Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius in July 2019.

The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers.

The vast majority of the conduct in question occurred prior to our acquisition of IG&E.

In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5 -year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.

Winter Storm Uri Legal Proceedings

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

Oral argument was held in April 2022.

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.

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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.

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 we and other parties may continue disputing the pricing during Winter Storm Uri through the ERCOT process and, to the extent the outcome of that process comes before the PUCT for review, the PUCT has not prejudged or made a final decision on that matter.

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.

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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 the three months ended March 31, 2021, 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.

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

Brazos Electric Cooperative Inc.

(Brazos) Bankruptcy — As a result of the lengthy period of peak pricing administratively imposed by the PUCT during Winter Storm Uri, certain market participants within ERCOT were not able to pay their full obligations to ERCOT.

Consequently, ERCOT was "short-paid" approximately $ 2.9 billion, the majority of which was related to Brazos, a Texas-based non-profit electric cooperative corporation that provides wholesale electricity to its members, which, in turn, provide retail electricity to Texas consumers.

In March 2021, Brazos commenced a Chapter 11 bankruptcy case in the U.S.

Bankruptcy Court for the Southern District of Texas.

As part of the Brazos bankruptcy proceeding, ERCOT filed a claim to recover approximately $ 1.9 billion from Brazos.

In response, Brazos filed an adversary proceeding against ERCOT seeking to disallow or greatly reduce ERCOT's claim.

ERCOT and Brazos subsequently engaged in mediation to resolve the dispute as an alternative to ERCOT's imposition of its market default protocols, which specify recovery of these losses through issuance of default uplift invoices to all market participants.

Under this short-pay recovery process, uplifted short-paid amounts are allocated to all market participants based on market share on a monthly basis until the full short-paid amounts are recovered.

The ERCOT protocols limit the amount of short-paid amounts that ERCOT can uplift to the entire market to $ 2.5 million per month which would have taken approximately 63 years to recover the full Brazos short-pay claim.

As a result of applying these standard ERCOT market default protocols, we recognized an approximately $ 189 million default uplift liability in the first quarter of 2021 based on our market share, which was subsequently reduced to $ 124 million as ERCOT collected amounts owed from certain defaulting entities through other means, primarily through securitization.

After extensive negotiations, Brazos and ERCOT reached a settlement in September 2022 that was incorporated in a proposed Brazos plan of reorganization filed with the bankruptcy court.

Under the settlement, Brazos owed two payments to ERCOT upon its emergence from bankruptcy:

first, an approximately $ 600 million payment, which ERCOT would use to replenish its Congestion Revenue Rights (CRR) Reserve Account and pay down its portion of the securitization program adopted by the legislature for electric cooperatives and municipal-owned utilities, and second, an approximately $ 554 million payment to fund an initial distribution to be made by ERCOT to market participants with claims against the Brazos short-pay based on each market participant's payment election.

Brazos would also make certain installment payments (of up to $ 13.8 million per year over 12 years) and contribute a portion of the proceeds from the sale of its generation assets (approximately $ 117 million) to fund payments, to be distributed by ERCOT, to the applicable market participants.

Importantly, the settlement precludes ERCOT from collecting default uplift from market participants for any prepetition amounts owed by Brazos ( i.e.

, it supplants the process to uplift the short-pay claim to market participants), and allows Vistra to extinguish the remaining $ 124 million default uplift liability to ERCOT on account of the Brazos short pay following confirmation of the Brazos plan of reorganization.

In September 2022, Brazos filed its plan of reorganization with the bankruptcy court and the proposed ERCOT settlement agreement was subject to the Brazos bankruptcy plan voting and confirmation processes, which concluded in November 2022 when the Brazos plan of reorganization was approved by the bankruptcy court.

In December 2022, the Brazos plan of reorganization became effective.

Accordingly, the $ 124 million default uplift liability to ERCOT, which was entirely attributable to the Brazos default, was derecognized in the fourth quarter of 2022 and recognized as revenue in the statement of operations.

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.

In addition, a number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been, and continue to be, 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.

Additional personal injury cases that have been, and continue to be, filed on behalf of additional plaintiffs have been consolidated with the MDL 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

In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (the Environment Executive Order) which directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives.

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

The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri, and that case has also now been consolidated with the MDL proceedings.

In the summer of 2022, various defendant groups filed motions to dismiss five so-called bellwether cases, and the MDL court heard oral argument on those motions in October 2022.

In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other defendant groups, including the retail electric providers and ERCOT.

In February 2023, the generator defendants filed a mandamus petition with the Houston Court of Appeals to review the MDL court's denial of the motion to dismiss.

We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously.

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.

In July 2019, the EPA finalized a rule 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.

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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.

In June 2022, the U.S.

Supreme Court issued an opinion reversing the D.C.

Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting.

In October 2022, the D.C.

Circuit Court issued an amended judgment, denying petitions for review of the ACE rule and challenges to the repeal of the CPP.

In addition, the EPA has opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d) and has indicated its intent to issue a new proposal in Spring 2023.

Cross-State Air Pollution Rule (CSAPR)

In October 2015, the EPA revised the primary and secondary ozone NAAQS to lower the 8-hour standard for ozone emissions during ozone season (May to September).

As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS.

In February 2023, the EPA disapproved Texas's SIP.

In April 2022, prior to the EPA's disapproval of Texas's SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS.

The proposed FIP would apply to 25 states beginning with the 2023 ozone seasons.

States where Vistra operates generation units that would be subject to this proposed rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia.

The revised Group 3 trading program (previously established in the Revised CSAPR Update Rule) would include emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants.

Starting in 2026, the budgets would be based on levels achieved through installation of selective catalytic reduction (SCR) controls at the approximately 20 % of large coal-fueled power plants that do not currently have such controls.

Starting in 2025, the budgets would be updated annually to account for source retirements.

Starting in 2024, the rule would also impose a daily emissions rate limit for coal-fueled units with existing controls and would impose such a limit for units installing new controls in 2027.

We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions.

The EPA is expected to finalize the proposed FIP in March 2023.

In February 2022, the State of Texas, Luminant, certain trade groups, and others filed legal challenges to the EPA's disapproval of Texas's SIP in the U.S.

Court of Appeals for the Fifth Circuit (Fifth Circuit Court).

If the EPA finalizes the FIP described above as expected in March 2023, it will impose reduced ozone season NO X budgets under the CSAPR program for our Texas power plants.

We cannot predict the outcome of our legal challenges to the EPA's disapproval of the SIP, any legal action related to the EPA's FIP once finalized, or the effects of the final rule (after the conclusion of legal challenges) on operations of our generation fleet.

Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas

In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP).

In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 SIP and a partial FIP.

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.

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

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.

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

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.

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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 EPA has stated it is starting a proceeding for reconsideration of the BART rule, which we expect in 2023.

The challenges in the D.C.

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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 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 February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court.

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 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.

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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.

We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 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.

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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.

The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval.

Effluent Limitation Guidelines (ELGs)

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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.

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 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.

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.

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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

CCR/Groundwater

In August 2018, the D.C.

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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.

In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications.

In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units.

The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules.

These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions.

In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C.

Circuit Court and have asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures.

The State of Texas and the TCEQ have intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA.

Briefing on this petition will be complete by May 2023.

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.

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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 (PRN) 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 Dynegy Midwest Generation, LLC (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.

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 June 2021, the Seventh Circuit Court affirmed the district court's dismissal of the lawsuit.

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.

We answered that complaint in July 2021, and this matter remains in the very early stages.

We answered that complaint in July 2021, and this matter is currently abated.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments.

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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).

The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan.

These proposed closure costs are reflected in the ARO in our consolidated balance sheets (see Note 20).

In July 2019, coal ash disposal and storage legislation in Illinois was enacted.

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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.

In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule and that case remains pending.

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.

One additional closure construction application will be filed for our Baldwin facility in 2023.

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.

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 rule required us to undertake further site specific evaluations required by each program.

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

In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO.

In May 2015, three complaints were filed at the FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO.

Dynegy is a named party in one of the complaints.

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We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations.

The Illinois Industrial Energy Consumers filed a related complaint at FERC against MISO in June 2015 requesting prospective changes to the MISO tariff.

The Illinois Industrial Energy Consumers filed a related complaint at the FERC against MISO in June 2015 requesting prospective changes to the MISO tariff.

Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint.

In October 2015, FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA.

In December 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction.

In October 2015, the FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of the FERC orders, rules and regulations occurred before or during the PRA.

In December 2015, the FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction.

The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order.

In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed.

FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff.

With the issuance of the order, this matter has been resolved in Dynegy's favor.

The request for rehearing was denied by FERC in March 2020.

In July 2019, the FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed.

The FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff.

A request for rehearing was denied by the FERC in March 2020.

The order was appealed by Public Citizen, Inc.

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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.

Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that the 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 the 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 the 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 the 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.

filed a motion at the FERC requesting that the 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 filed a response to this motion and will continue to vigorously defend our position.

In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction.

Although the FERC directed the Office of Enforcement to file a remand report, the FERC stated in the June 2022 order that it is not reopening the Office of Enforcement investigation.

In September 2022, the Office of Enforcement filed its remand report stating that the Office of Enforcement staff found during its investigation that Dynegy knowingly engaged in manipulative behavior to set the Zone 4 price in the 2015-2016 PRA.

The Company intends to reply substantively to this submission, and to vigorously defend its position, consistent with the FERC's scheduling orders.

Other Matters

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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-, 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.

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 2023 and August 2025, 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.

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Under the SFP, in the event of any single nuclear liability loss in excess of $ 450 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S.

is subject to an annual assessment of up to $ 137.6 million.

is subject to an assessment of up to $ 137.6 million.

This approximately $ 137.6 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2023.

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Balance at December 31, 2019 528,741,335 ( 41,043,224 ) 487,698,111

Shares issued (a) (b) 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

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Shares retired ( 3,397 ) — ( 3,397 )

Shares repurchased (b) — ( 27,988,518 ) ( 27,988,518 )

Balance at December 31, 2021 532,929,476 ( 69,031,742 ) 463,897,734

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Shares retired ( 12,979 ) — ( 12,979 )

Shares repurchased (c) — ( 27,988,518 ) ( 27,988,518 )

Shares repurchased (b) — ( 78,470,547 ) ( 78,470,547 )

Balance at December 31, 2022 537,179,072 ( 147,502,289 ) 389,676,783

(a) Shares issued includes share awards granted to nonemployee directors.

(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.

(b) Shares repurchased include 78,087 and 5,174,863 of unsettled shares purchased as of December 31, 2022 and 2021, respectively.

Share Repurchase Programs

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.

Current Share Repurchase Program — In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $ 2.0 billion of our outstanding shares of common stock may be repurchased.

The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date.

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.

In August 2022, the Board authorized an incremental $ 1.25 billion for repurchases to bring the total authorized under the Share Repurchase Program to $ 3.25 billion.

$3.25 Billion Board Authorization

Total Number of Shares Repurchased Average Price Paid

Per Share Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period

Year Ended December 31, 2021

19,330,365 $ 21.16 $ 409

Year Ended December 31, 2022

78,470,547 23.40 1,836

Total repurchased through December 31, 2022 (a)

97,800,912 $ 22.96 $ 2,245 $ 1,005

January 1, 2023 through February 23, 2023 8,824,640 22.72 201

Total repurchased through February 23, 2023 106,625,552 $ 22.94 $ 2,446 $ 804

(a) Shares repurchased include 78,087 of unsettled shares repurchased for $ 2 million as of December 31, 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.

Superseded Share Repurchase Program — 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 on January 1, 2021.

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, 2018 Share Repurchase Program).

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.

The 2020 Share Repurchase Program was superseded by the Share Repurchase Program described above in October 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).

On October 15, 2021 (Series A Issuance Date), we issued 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).

On December 10, 2021 (Series B Issuance Date), we issued 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.

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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.

Common Stock Dividends — In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019.

Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations.

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.

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).

Quarterly dividends declared and paid per share of common stock for the years ended December 31, 2022, 2021 and 2020 are reflected in the table below.

Year Ended December 31, 2022 Year Ended December 31, 2021 Year Ended December 31, 2020

Board Declaration Date Payment

Date Per Share Amount Board Declaration Date Payment

Date Per Share Amount

February 2022 March 2022 $ 0.170 February 2021 March 2021 $ 0.150 February 2020 March 2020 $ 0.135

May 2022 June 2022 $ 0.177 April 2021 June 2021 $ 0.150 April 2020 June 2020 $ 0.135

July 2022 September 2022 $ 0.184 July 2021 September 2021 $ 0.150 July 2020 September 2020 $ 0.135

October 2022 December 2022 $ 0.193 October 2021 December 2021 $ 0.150 October 2020 December 2020 $ 0.135

In February 2023, the Board declared a quarterly dividend of $ 0.1975 per share of common stock that will be paid in March 2023.

Preferred Stock Dividends — 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.

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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).

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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.

Semiannual dividends declared and paid per share of each respective preferred stock series for the year ended December 31, 2022 are reflected in the table below.

Dividends payable are recorded on board declaration date.

Year Ended December 31, 2022

Board Declaration Date Payment Date Per Share Amount

Series A Preferred Stock:

February 2022 April 2022 $ 40.00

July 2022 October 2022 $ 40.00

Series B Preferred Stock:

May 2022 June 2022 $ 35.97

October 2022 December 2022 $ 35.00

In February 2023, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2023.

Dividend Restrictions

The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder.

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 $ 405 million, $ 1.1 billion and $ 3.9 billion during the years ended December 31, 2021, 2020 and 2019, respectively.

The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder.

As of December 31, 2022, Vistra Operations can distribute approximately $ 4.2 billion to Parent under the Vistra Operations Credit 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 $ 1.775 billion, $ 405 million and $ 1.1 billion during the years ended December 31, 2022, 2021 and 2020, 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, 2022, 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.

In addition to the restrictions under the Vistra Operations Credit 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.

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During the years ended December 31, 2022, 2021 and 2020, we recorded changes in the funded status of our pension and other postretirement employee benefit liability totaling $( 23 ) million, $( 24 ) million and $ 23 million, respectively.

During the years ended December 31, 2021, 2020 and 2019, $( 8 ) million, $( 5 ) million and $( 3 ) million respectively was reclassified from accumulated other comprehensive income and reported in other deductions.

During the years ended December 31, 2022, 2021 and 2020, zero , $( 8 ) million and $( 5 ) million respectively was reclassified from accumulated other comprehensive income and reported in other deductions.

At the Merger Date, the Company entered into an agreement whereby the holder of each outstanding warrant previously issued by Dynegy would be entitled to receive, upon paying an exercise, price of $ 35.00 (subject to adjustment from time to time), the number of shares of Vistra common stock that such holder would have been entitled to receive if it had held one share of Dynegy common stock at the closing of the Merger, or 0.652 shares of Vistra common stock.

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.

In January 2022, in accordance with the terms of the warrant agreement, the exercise price of each warrant was adjusted downward to $ 34.00 (subject to further adjustment from time to time), or $ 52.15 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received.

As of December 31, 2022, nine million warrants expiring in 2024 were outstanding.

The warrants were included in equity based on their fair value at the Merger Date.

Tangible Equity Units (TEUs)

At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00 % TEUs, each with a stated amount of $ 100.00 and each comprised of (i) a prepaid stock purchase contract that delivered to the holder on July 1, 2019, 4.0813 shares of Vistra common stock per contract with cash paid in lieu of any fractional shares at a rate of $ 22.5954 per share and (ii) a senior amortizing note with an outstanding principal amount of $ 38 million at the Merger Date that paid an equal quarterly cash installment of $ 1.75 per amortizing note (see Note 11).

In the aggregate, the annual quarterly cash installments were equivalent to a 7.00 % cash payment per year with respect to each $ 100.00 stated amount of TEUs.

The amortizing notes were accounted for as debt while the stock purchase contract was included in equity based on the fair value of the contract at the Merger Date (see note 11).

The entire class of TEUs were suspended from trading on the New York Stock Exchange on July 1, 2019 and removed from listing and registration on July 12, 2019.

On July 1, 2019, approximately 18.8 million treasury shares of Vistra common stock were issued in connection with the settlement of all outstanding TEUs.

FAIR VALUE MEASUREMENTS

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(b) Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our consolidated balance sheets.

(c) The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets.

(d) The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our consolidated balance sheets.

Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.

Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales.

Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates.

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Financial transmission rights 132 ( 31 ) 101 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 35 ) to $ 10 $ ( 11 )

Natural gas 29 ( 86 ) ( 57 ) Income Approach Gas basis (h) $ ( 1 ) to $ 16 $ 8

Natural gas 20 ( 155 ) ( 135 ) Income Approach Gas basis and illiquid delivery periods (h) $ — to $ 30 $ 13

Coal 21 ( 1 ) 20 Income Approach Probability of default (i) — % to 40 % 20 %

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(g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.

(h) Primarily based on the historical forward PJM and Northeast gas basis prices.

(h) Primarily based on the historical forward PJM and Northeast gas basis prices and fixed 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.

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Net asset (liability) balance at beginning of period $ ( 360 ) $ 22 $ ( 74 )

Total unrealized valuation gains (losses) (a) ( 53 ) ( 5 ) 8

Total unrealized valuation losses (a) ( 1,382 ) ( 53 ) ( 5 )

Purchases, issuances and settlements (b):

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Unrealized valuation gains (losses) relating to instruments held at end of period $ ( 977 ) $ ( 364 ) $ 18

(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.

(a) For the years ended December 31, 2022 and 2021, Retail segment includes unrealized net losses of $ 901 million and $ 341 million, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 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.

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All Level 3 transfers during the periods presented are in and out of Level 2.

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.

For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, gas, and coal derivatives where forward pricing inputs have become observable.

For the year ended December 31, 2021, transfers out of Level 3 primarily consist of gas and power 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.

Substantially all changes in values of commodity contracts are reported as operating revenues in our consolidated statements of operations.

COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

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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.

During the years ended December 31, 2022 and 2021, net losses of $ 544 million and $ 298 million, respectively, were recognized in operating revenues due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term.

These amounts are reflected in commodity contracts derivative liabilities as of December 31, 2022 and 2021.

December 31, 2022

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As of December 31, 2022, total credit risk exposure to all counterparties related to derivative contracts totaled $ 5.840 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.

The net exposure to those counterparties totaled $ 1.064 billion at December 31, 2022 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure totaling $ 136 million.

As of December 31, 2022, the credit risk exposure to the banking and financial sector represented 80 % of the total credit risk exposure and 36 % of the net exposure.

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Expected return on assets ( 19 ) ( 18 ) ( 23 ) ( 1 ) ( 2 ) ( 2 )

Amortization of unrecognized amounts 3 1 — 5 4 3

Amortization of unrecognized amounts, net — 3 1 — 5 4

Immediate pension and postretirement benefit cost — — 7 — — ( 1 )

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Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:

Net (gain) loss and prior service (credit) cost $ ( 29 ) $ 17 $ 11 $ ( 12 ) $ 5 $ —

Net (gain) loss $ ( 16 ) $ ( 27 ) $ 28 $ ( 22 ) $ ( 10 ) $ 9

Prior service (credit) cost 9 — — — ( 2 ) ( 3 )

Curtailment and settlements — ( 2 ) ( 11 ) — — ( 1 )

Total recognized in net periodic benefit cost and other comprehensive income $ ( 5 ) $ ( 23 ) $ 28 $ ( 18 ) $ ( 4 ) $ 12

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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.

Retirement Plan — For the year ended December 31, 2022, the net actuarial gain of $ 16 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, gains attributable to actuarial assumption updates to reflect current market conditions and plan experience different than expected, partially offset by losses attributable to actual asset performance exceeding expectations and settlements.

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.

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.

OPEB Plans — For the year ended December 31, 2022, the net actuarial gain of $ 22 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, plan experience different than expected and updates to health care assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and updates to health care assumptions, partially offset by losses attributable to actual asset performance falling short of expectations.

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 period 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.

Retirement Plan OPEB Plans

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Participant contributions — — 2 3

Lump-sum window — ( 6 ) — —

Annuity purchase — ( 29 ) — —

Actuarial loss ( 11 ) 46 ( 6 ) 12

Plan amendments 9 — — —

Actuarial gain ( 113 ) ( 11 ) ( 30 ) ( 6 )

Benefits paid ( 73 ) ( 48 ) ( 13 ) ( 13 )

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Participant contributions — — 2 3

Lump-sum window — ( 6 ) — —

Annuity purchase — ( 29 ) — —

Actual gain on assets 30 40 3 4

Actual gain (loss) on assets ( 77 ) 30 ( 6 ) 3

Transfers — — ( 2 ) —

Benefits paid ( 73 ) ( 46 ) ( 13 ) ( 13 )

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Amounts Recognized in the Balance Sheet Consist of:

Other noncurrent assets $ — $ — $ 26 $ 23

Investments $ — $ — $ 20 $ 26

Other current liabilities — — ( 8 ) ( 9 )

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Amounts Recognized in Accumulated Other Comprehensive Income Consist of:

Net actuarial (gain) loss $ ( 4 ) $ ( 13 ) $ ( 15 ) $ 7

Prior services (credit) cost 9 — 1 1

Net loss and prior service cost $ 5 $ ( 13 ) $ ( 14 ) $ 8

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:

Retirement Plan — As of December 31, 2022 and 2021, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following:

Asset Category:

Interest-bearing cash (a) $ 2 $ —

Cash commingled trusts 4 11

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Fixed income securities:

Corporate bonds (a) 199 207

Corporate bonds (b) 107 199

Government bonds 44 31

Other (b) 30 32

Other (c) 24 30

Real estate 43 50

Hedge funds 16 —

Total assets measured at net asset value $ 320 $ 470

(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)

(a) Interest -bearing cash is classified as Level 2.

(b) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

OPEB Plans — As of December 31, 2022 and 2021, the Vistra OPEB plan assets measured at fair value totaled $ 29 million and $ 39 million, respectively.

At December 31, 2022 and 2021, assets consisted of $ 28 million and $ 37 million, respectively, of comingled funds valued at net asset value and $ 1 million and $ 2 million, respectively, of municipal bond and cash equivalent mutual funds classified as Level 1.

Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets

The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets.

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International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.

Real estate and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.

Real estate, hedge funds and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.

On December 30, 2022, the EEI Plan merged into the Dynegy Plan.

The target asset allocation ranges of pension plan investments by asset category are as follows:

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Asset Category:

Vistra Plan Dynegy Plan EEI Plan

Vistra Plan Dynegy Plan

Fixed income 50 % - 70 % 44 % - 54 %

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Credit strategies 2 % 6 % 3 % - 7 %

Hedge funds 2 % - 6 % 3 % - 7 %

Retirement Plan Expected Long-Term Rate of Return on Assets Assumption

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Expected Long-Term Rate of Return

Vistra Plan Dynegy Plan EEI Plan

Vistra Plan Dynegy Plan

Fixed income securities 5.2 % 5.1 %

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Credit strategies 7.0 % 7.0 %

Hedge funds 7.5 % 7.5 %

Weighted average 5.8 % 5.8 %

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Contributions

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.

Contributions to the Retirement Plan for the years ended December 31, 2022, 2021 and 2020 totaled zero , $ 1 million and $ 16 million, respectively, and no contributions are expected to be made in 2023.

OPEB plan funding for each year ended December 31, 2022, 2021 and 2020 totaled $ 9 million and funding in 2023 is expected to total $ 9 million.

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Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.

At the Merger Date, Vistra assumed Dynegy's participant-directed defined contribution plan.

In January 2019, this plan was merged into the Thrift Plan.

Aggregate employer contributions to the qualified savings plans totaled $ 33 million, $ 34 million and $ 34 million for the years ended December 31, 2022, 2021 and 2020, respectively.

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Expected volatility is based on an average of the historical, daily volatility of a peer group selected by Vistra over a period consistent with the expected life assumption ending on the grant date.

We assumed no dividend yield in the valuation of the options granted from 2016 through 2018, and assumed 2.3 % and 1.9 % dividend yields in the valuation of options granted in 2020 and 2019, respectively.

These options may be exercised over either three- or four-year graded vesting periods and will expire 10 years from the grant date.

We assumed a 2.3 % dividend yield in the valuation of options granted in 2020.

These options may be exercised over a three year graded vesting period and will expire 10 years from the grant date.

No options were issued in 2021 or 2022.

Stock options outstanding at December 31, 2022 are all held by current or former employees.

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Total outstanding at beginning of period 13,947 $ 19.28 5.9 $ 55.7

Granted — $ —

Exercised ( 2,763 ) $ 15.65

2 unchanged sentences

Exercisable at December 31, 2022 7,914 $ 19.92 5.1 $ 31.4

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.

As of December 31, 2022, $ 2 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 3 months.

Restricted Stock Units

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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.

We recognized compensation expense associated with PSUs of $ 22 million, $ 9 million and $ 15 million for the years ended December 31, 2022, 2021 and 2020, respectively.

As of December 31, 2022, we have $ 33 million of unrecognized compensation cost associated with PSUs.

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(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 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.

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.

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.

Our Chief Executive Officer is our Chief Operating Decision Maker (CODM).

Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations.

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The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management.

The Texas segment represents results from the ERCOT market and was referred to as the ERCOT segment prior to the third quarter of 2020.

The East segment represents results from the PJM, ISO-NE and NYISO markets.

The Texas segment represents results from Vistra's electricity generation operations in the ERCOT market, other than assets that are now part of the Sunset or Asset Closure segments.

The East segment represents results from 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, and includes operations in the PJM, ISO-NE and NYISO markets.

We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics.

The West segment represents results from the CAISO market, including our development of battery ESS projects at our Moss Landing and Oakland power plant sites (see Note 3).

The Sunset segment consists of generation plants with announced retirement plans.

The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing and Oakland power plant sites (see Note 2).

The Sunset segment consists of generation plants with announced retirement dates after December 31, 2022.

Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments.

We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement plans.

We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement dates after December 31, 2022.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3).

The Asset Closure segment also includes results from generation plants we retired in the year ended December 31, 2022.

Upon movement of generation plant assets to either the Sunset or Asset Closure segments, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes.

Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines.

We have not allocated any unrealized gains or losses on the commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018, 2019 and 2020.

We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 up until the retirement date.

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.

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.

Our CODM uses more than one measure to assess segment performance, but primarily focuses on Adjusted EBITDA.

While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by U.S.

GAAP and may not be comparable to non-GAAP metrics presented by other companies.

Adjusted EBITDA is most comparable to consolidated net income (loss) prepared based on U.S.

We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices.

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December 31, 2020 ( 11 ) 677 ( 23 ) ( 10 ) ( 122 ) ( 18 ) — ( 329 ) 164

(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 generally not reflected in net income of the segments but is reflected almost entirely in Corporate and Other net income.

(1) For the years ended December 31, 2022 and 2021, Retail segment includes unrealized net losses of $ 544 million and $ 298 million, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term.

(2) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.

(b) Income tax (expense) benefit is generally not reflected in net income (loss) of the segments but is reflected almost entirely in Corporate and Other net income (loss).

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 fourth quarter of 2022, we recognized an impairment loss of $ 74 million related to our Miami Fort generation facility in Ohio as a result of a significant decrease in the projected operating margins of the facility, reflecting an increase in projected coal costs along with a decrease in projected power prices.

The impairment is reported in our Sunset segment and includes write-downs of property, plant and equipment of $ 71 million and write-downs of inventory of $ 3 million.

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 facility, reflecting a decrease in the economic forecast of the facility and the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.

The impairment is reported in our Asset Closure segment and includes write-downs of property, plant and equipment of $ 33 million and write-downs of inventory of $ 5 million.

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 3 and 12).

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.

The impairment for our Kincaid facility is reported in our Sunset segment and includes write-downs of property, plant and equipment of $ 166 million and write-downs of inventory of $ 7 million.

The impairment for our Zimmer facility is reported in our Asset Closure segment and includes write-downs of property, plant and equipment of $ 94 million and write-downs of inventory of $ 5 million.

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.

We also recorded a $ 32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facility and therefore determined to have a significant decrease in estimated useful life.

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.

The impairments are reported in our Asset Closure segment and include write-downs of property, plant and equipment of $ 45 million, write-downs of intangible assets of $ 32 million and write-downs of inventory of $ 7 million.

In determining the fair value of the impaired assets in 2022, 2021, and 2020, we utilized the income approach described in ASC 820, Fair Value Measurement and, if applicable, applied weighting to prices and other relevant information generated by market transactions involving similar assets.

Interest Expense and Related Charges

16 unchanged sentences

Sale of land (b) 8 9 8

Funds released from escrow to settle pre-petition claims of our predecessor (c) — — 9

Interest income 19 — 2

2 unchanged sentences

Other deductions:

Loss on disposal of investment in NELP (d) $ — $ 29 $ —

Loss on disposal of investment in NELP (c) $ — $ — $ 29

All other 4 16 13

Total other deductions $ 4 $ 16 $ 42

(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.

(a) For the year ended December 31, 2022, $ 62 million reported in the Texas segment, $ 6 million reported in the West segment, $ 1 million in the Asset Closure segment and $ 1 million reported in the Corporate and Other non-segment.

For the year ended December 31, 2021, $ 80 million reported in the Texas segment, $ 7 million reported in the Asset Closure 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.

Restricted Cash

38 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 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.

Equity earnings related to our investment in NELP totaled $ 3 million for the year ended December 31, 2020, recorded in equity in earnings of unconsolidated investment in our consolidated statements of operations.

We received distributions totaling $ 3 million for the year ended December 31, 2020.

Nuclear Decommissioning Trust

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Decommissioning costs are being recovered from Oncor customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund.

Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability, are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates.

Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability, are offset by a corresponding change in a regulatory asset/liability (currently a regulatory asset reported in other noncurrent assets) that will ultimately be settled through changes in Oncor's delivery fees rates.

If funds recovered from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra, provided that Vistra complied with PUCT rules and regulations regarding decommissioning trusts.

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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 2.54 % 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.

The debt securities had an average coupon rate of 2.64 % and 2.54 % as of December 31, 2022 and 2021, respectively, and an average maturity of 11 years and 10 years as of December 31, 2022 and 2021, respectively.

(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.

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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.

As of December 31, 2022 and 2021, asbestos removal liabilities totaled zero and $ 3 million, respectively.

We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets.

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.

As of December 31, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $ 1.688 billion, which is higher 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 asset has been recorded to our consolidated balance sheet of $ 40 million in other noncurrent assets.

The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our consolidated balance sheets, for the years ended December 31, 2022, 2021 and 2020:

2 unchanged sentences

Accretion 46 20 23 89

Adjustment for change in estimates — 16 ( 1 ) 15

Adjustment for obligations assumed through acquisitions — — ( 3 ) ( 3 )

Adjustment for change in estimates (a) 219 ( 6 ) 25 238

Payments — ( 65 ) ( 49 ) ( 114 )

Liability transfers (a) — — ( 135 ) ( 135 )

Liability transfers (b) — — ( 15 ) ( 15 )

Liability at December 31, 2020 1,585 359 492 2,436

Accretion 50 16 22 88

Adjustment for change in estimates (b) 219 ( 6 ) 25 238

Adjustment for change in estimates — 13 1 14

Payments — ( 68 ) ( 20 ) ( 88 )

Liability transfers (a) — — ( 15 ) ( 15 )

Liability at December 31, 2021 1,635 320 495 2,450

2 unchanged sentences

Payments — ( 70 ) ( 18 ) ( 88 )

Liability transfers (b) — ( 2 ) ( 59 ) ( 61 )

Liability at December 31, 2022 1,688 284 465 2,437

1 unchanged sentence

Noncurrent liability at December 31, 2022 $ 1,688 $ 179 $ 442 $ 2,309

(a) Represents ARO transferred to a third-party for remediation.

Any remaining unpaid third-party obligation has been reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.

(b) The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2020.

(a) The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2020.

Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occur, and the PUCT requires a new cost estimate at least every five years.

1 unchanged sentence

Department of Energy is estimated to begin accepting spent fuel offsite.

(b) Represents ARO transferred to a third-party for remediation.

Any remaining unpaid third-party obligation has been reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.

Other Noncurrent Liabilities and Deferred Credits

3 unchanged sentences

Identifiable intangible liabilities (Note 5) 140 147

Regulatory liability 325 89

Regulatory liability (b) — 325

Finance lease liabilities 237 235

4 unchanged sentences

Total other noncurrent liabilities and deferred credits $ 1,004 $ 1,489

(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.

(a) As of December 31, 2022 and 2021, includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

As of December 31, 2021, also includes the allocation of ERCOT default uplift charges.

See Note 12 for further discussion of the derecognition of ERCOT default uplift charges in the fourth quarter of 2022.

(b) As of December 31, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning was higher than the fair value of the assets contained in the nuclear decommissioning trust and recorded as a regulatory asset of $ 40 million in other noncurrent assets.

As of December 31, 2021, the fair value of the assets contained in the nuclear decommissioning trust was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $ 325 million in other noncurrent liabilities and deferred credits.

Fair Value of Debt

18 unchanged sentences

Total cash, cash equivalents and restricted cash $ 525 $ 1,359

The following table summarizes our supplemental cash flow information for the years ended December 31, 2021, 2020 and 2019, respectively.

The following summarizes our supplemental cash flow information for the years ended December 31, 2022, 2021 and 2020, respectively.

Year Ended December 31,

4 unchanged sentences

Interest paid (net of capitalized interest) $ 552 $ 456 $ 482

Income taxes paid / (refunds received) (a) $ ( 50 ) $ ( 140 ) $ ( 76 )

Noncash investing and financing activities:

Accrued property, plant and equipment additions (b) $ 171 $ 19 $ 67

Accrued property, plant and equipment additions (a) $ 103 $ 171 $ 19

Disposition of investment in NELP $ — $ — $ 123

Acquisition of investment in NJEA $ — $ — $ 90

Shares issued for tangible equity unit contracts (Note 14) $ — $ — $ 446

Land transferred with liability transfers $ — $ — $ 16

(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.

(a) Represents property, plant and equipment accruals during the period for which cash has not been paid as of the end of the period.

For the years ended December 31, 2022, 2021 and 2020, we paid federal income taxes of $ 1 million, zero and zero , respectively, paid state income taxes of $ 33 million, $ 52 million and $ 40 million, respectively, received federal tax refunds of zero , zero and $ 170 million, respectively, and received state tax refunds of $ 8 million, $ 2 million and $ 10 million, respectively.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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