NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.
Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users. Effective July 2, 2020, we changed our name from Vistra Energy Corp. to Vistra Corp. (Vistra) to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect or integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business leading the clean power transition through our Vistra Zero portfolio while powering the communities we serve with safe, reliable and affordable power.
Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 19 for further information concerning our reportable business segments.
Winter Storm Uri
In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our 2021 results of operations and operating cash flows.
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 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
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
The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2021 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of derivative contracts rather than collateral. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 14 and 15 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. As of December 31, 2022 and 2021, there were no derivative positions accounted for as cash flow or fair value hedges.
We report commodity hedging and trading results as revenue, fuel expense or purchased power in the consolidated statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges and trading activities are primarily reported as revenue. Physical or financial hedges for coal, diesel or uranium, along with physical natural gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the consolidated statements of operations in interest expense.
Revenue Recognition
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts. See Note 4 for detailed descriptions of revenue from contracts with customers. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.
Advertising Expense
We expense advertising costs as incurred and include them within SG&A expenses. Advertising expenses totaled $47 million, $48 million and $43 million for the years ended December 31, 2022, 2021 and 2020, respectively.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 20 for details of impairments of long-lived assets recorded in 2022, 2021 and 2020.
Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 5 for details of intangible assets with finite lives, including discussion of fair value determinations.
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 or purchase consideration is allocated to goodwill. We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See Note 5 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations.
Nuclear Fuel
Nuclear fuel is capitalized and reported as a component of our property, plant and equipment in our consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs and delivery fees in our consolidated statements of operations.
Major Maintenance Costs
Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in our consolidated statements of operations.
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 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. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates.
See Note 16 for additional information regarding pension and OPEB plans.
Stock-Based Compensation
Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. The fair value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model. Forfeitures are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. See Note 17 for additional information regarding stock-based compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as "pass through" items on the consolidated balance sheets with no effect on the consolidated statements of operations (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in our consolidated statements of operations).
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in our consolidated statements of operations.
Income Taxes
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. See Note 6.
We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 6.
Tax Receivable Agreement (TRA)
The Company accounts for its obligations under the TRA as a liability in our consolidated balance sheets (see Note 7). The carrying value of the TRA obligation represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business.
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the estimated 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. These changes are included on our consolidated statements of operations under the heading of Impacts of Tax Receivable Agreement.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 12 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered cash equivalents.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. See Note 20 for more details regarding restricted cash.
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 Note 2). 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. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 20.
Depreciation of our property, plant and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 20.
Asset Retirement Obligations (ARO)
A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which capitalized costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 20.
Regulatory Asset or Liability
The costs to ultimately decommission the Comanche Peak nuclear power plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in our consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits.
Inventories
Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (calculated on a weighted average basis) or net realizable value. We expect to recover the value of inventory costs in the normal course of business. See Note 20.
Investments
Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 20 for discussion of these and other investments.
Noncontrolling Interest
Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. 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.
Treasury Stock
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. See Note 13.
Leases
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.
Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in operating lease ROU assets, operating lease liabilities (current) and operating lease liabilities (noncurrent) on our consolidated balance sheet. Finance leases are included in property, plant and equipment, other current liabilities and other noncurrent liabilities and deferred credits on our consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842 to not separate lease and non-lease components for a majority of our lease asset classes.
Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.
We also present lessor sublease income on a net basis against the related lessee lease expense.
Adoption of Accounting Standards Issued Prior to 2022
Simplifying the Accounting for Income Taxes — In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2019-12, Simplifying the Accounting for Income Taxes (Topic 740). The ASU enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. We adopted all provisions of this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.
Changes to the Disclosure Requirements for Fair Value Measurement — In August 2018, the FASB issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement. The ASU removes disclosure requirements for (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of transfers between levels and (c) the valuation processes for Level 3. The ASU requires new disclosures around (a) the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. We adopted this ASU in the first quarter of 2020, and the updated disclosures are included in Note 14.
Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract — In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The ASU requires a customer in a cloud hosting arrangement that is a service contract to determine which implementation costs to capitalize and which costs to expense based on the project stage of the implementation. The ASU also requires the customer to expense the capitalized implementation costs over the term of the hosting arrangement. The customer is required to apply the existing impairment and abandonment guidance on the capitalized implementation costs. We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.
Financial Instruments — Credit Losses — In June 2016, the FASB issued ASU 2016-13, Financial Instruments — Credit Losses. The ASU requires organizations to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.
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 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.
2.DEVELOPMENT OF GENERATION FACILITIES
Texas Segment Solar Generation and Energy Storage 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
In September 2021, we announced the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. Estimated commercial operation dates for these facilities range from 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 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). The contract was amended to increase the capacity of the planned development to a 36.25 MW battery ESS. In April 2020, the concurrent Local Area Reliability Service (LARS) agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed, but required California Public Utilities Commission (CPUC) approval. PG&E did not receive CPUC approval as of April 15, 2021. On April 16, 2021, Vistra terminated the LARS agreement with PG&E. We are continuing development of the Oakland battery ESS project while seeking another contractual arrangement that will allow the investment to move forward.
Moss Landing — In June 2018, we announced that, subject to approval by the CPUC, we would enter into a 20-year resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California (Moss Landing Phase I). 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. Moss Landing Phase I commenced commercial operations in May 2021.
In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10-year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II). 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 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 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. 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.
3.RETIREMENT OF GENERATION FACILITIES
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.
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| 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 |
| Total | | | | | | | | 7,486 | | | | |
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(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.
4. REVENUE
The following tables disaggregate our revenue by major source:
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| Year Ended December 31, 2022 |
| Retail | | Texas | | East | | West | | Sunset | | Asset Closure | | Eliminations | | Consolidated |
| Revenue from contracts with customers: | | | | | | | | | | | | | | | |
| Retail energy charge in ERCOT | $ | 6,971 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,971 | |
| Retail energy charge in Northeast/Midwest | 2,139 | | | — | | | — | | | — | | | — | | | — | | | — | | | 2,139 | |
| Wholesale generation revenue from ISO/RTO | — | | | 1,105 | | | 1,209 | | | 467 | | | 1,120 | | | 392 | | | — | | | 4,293 | |
| Capacity revenue from ISO/RTO (a) | — | | | — | | | 20 | | | — | | | 63 | | | 20 | | | — | | | 103 | |
| Revenue from other wholesale contracts | — | | | 696 | | | 1,106 | | | 151 | | | 150 | | | 22 | | | — | | | 2,125 | |
| Total revenue from contracts with customers | 9,110 | | | 1,801 | | | 2,335 | | | 618 | | | 1,333 | | | 434 | | | — | | | 15,631 | |
| Other revenues: | | | | | | | | | | | | | | | |
| Intangible amortization | — | | | — | | | 1 | | | — | | | (7) | | | — | | | — | | | (6) | |
| Hedging and other revenues (b) | 345 | | | (640) | | | (316) | | | (291) | | | (858) | | | (138) | | | 1 | | | (1,897) | |
| Affiliate sales (c) | — | | | 2,572 | | | 1,686 | | | 9 | | | 488 | | | — | | | (4,755) | | | — | |
| Total other revenues | 345 | | | 1,932 | | | 1,371 | | | (282) | | | (377) | | | (138) | | | (4,754) | | | (1,903) | |
| Total revenues | $ | 9,455 | | | $ | 3,733 | | | $ | 3,706 | | | $ | 336 | | | $ | 956 | | | $ | 296 | | | $ | (4,754) | | | $ | 13,728 | |
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(a)Represents net capacity sold (purchased) in each ISO/RTO. 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 $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.
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| Year Ended December 31, 2021 |
| Retail | | Texas | | East | | West | | Sunset | | Asset Closure | | Eliminations | | Consolidated |
| Revenue from contracts with customers: | | | | | | | | | | | | | | | |
| Retail energy charge in ERCOT | $ | 5,733 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 5,733 | |
| Retail energy charge in Northeast/Midwest | 2,255 | | | — | | | — | | | — | | | — | | | — | | | — | | | 2,255 | |
| Wholesale generation revenue from ISO/RTO | — | | | 3,808 | | | 786 | | | 229 | | | 1,158 | | | 367 | | | — | | | 6,348 | |
| Capacity revenue from ISO/RTO (a) | — | | | — | | | (22) | | | 1 | | | 138 | | | 46 | | | — | | | 163 | |
| Revenue from other wholesale contracts | — | | | 2,302 | | | 602 | | | 104 | | | 192 | | | 1 | | | — | | | 3,201 | |
| Total revenue from contracts with customers | 7,988 | | | 6,110 | | | 1,366 | | | 334 | | | 1,488 | | | 414 | | | — | | | 17,700 | |
| Other revenues: | | | | | | | | | | | | | | | |
| Intangible amortization | (2) | | | — | | | 74 | | | — | | | (12) | | | — | | | — | | | 60 | |
| Hedging and other revenues (b) | (115) | | | (4,355) | | | 123 | | | 35 | | | (1,043) | | | (328) | | | — | | | (5,683) | |
| 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) | |
| Total revenues | $ | 7,871 | | | $ | 2,790 | | | $ | 2,587 | | | $ | 374 | | | $ | 653 | | | $ | 86 | | | $ | (2,284) | | | $ | 12,077 | |
____________
(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 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.
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| Year Ended December 31, 2020 |
| Retail | | Texas | | East | | West | | Sunset | | Asset Closure | | Eliminations | | Consolidated |
| Revenue from contracts with customers: | | | | | | | | | | | | | | | |
| Retail energy charge in ERCOT | $ | 5,813 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 5,813 | |
| Retail energy charge in Northeast/Midwest | 2,406 | | | — | | | — | | | — | | | — | | | — | | | — | | | 2,406 | |
| Wholesale generation revenue from ISO/RTO | — | | | 475 | | | 310 | | | 124 | | | 264 | | | 210 | | | — | | | 1,383 | |
| Capacity revenue from ISO/RTO (a) | — | | | — | | | (52) | | | — | | | 125 | | | 39 | | | — | | | 112 | |
| Revenue from other wholesale contracts | — | | | 226 | | | 668 | | | 54 | | | 187 | | | 1 | | | — | | | 1,136 | |
| Total revenue from contracts with customers | 8,219 | | | 701 | | | 926 | | | 178 | | | 576 | | | 250 | | | — | | | 10,850 | |
| Other revenues: | | | | | | | | | | | | | | | |
| Intangible amortization | (5) | | | — | | | 2 | | | — | | | (21) | | | — | | | — | | | (24) | |
| Hedging and other revenues (b) | 56 | | | 416 | | | (108) | | | 101 | | | 83 | | | 69 | | | — | | | 617 | |
| Affiliate sales | — | | | 2,999 | | | 1,595 | | | 3 | | | 298 | | | — | | | (4,895) | | | — | |
| Total other revenues | 51 | | | 3,415 | | | 1,489 | | | 104 | | | 360 | | | 69 | | | (4,895) | | | 593 | |
| Total revenues | $ | 8,270 | | | $ | 4,116 | | | $ | 2,415 | | | $ | 282 | | | $ | 936 | | | $ | 319 | | | $ | (4,895) | | | $ | 11,443 | |
____________
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $542 million of capacity purchased offset by $490 million of capacity sold. The Sunset segment includes $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. See Note 19 for unrealized net gains (losses) by segment.
Retail Energy Charges
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 60 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Wholesale Generation Revenue from ISOs/RTOs
Revenue is recognized when volumes are delivered to the ISO/RTO. Revenue is recognized over time using the output method based on kilowatt hours delivered and cash is settled within 10 days of invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues.
Capacity Revenue From ISO/RTO
We offer generation capacity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers. Capacity ensures installed generation and demand response is available to satisfy system integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period. The penalties are recorded as a reduction to revenue. When capacity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue.
Revenue from Other Wholesale Contracts
Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Revenue is recognized when the service is performed. Revenue is recognized over time using the output method based on kilowatt hours delivered or other applicable measurements, and cash settles shortly after invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted for as a single performance obligation.
Other Revenues
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 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. We have classified all sales to affiliates that are eliminated in consolidation as other revenues in the table above.
Contract and Other Customer Acquisition Costs
We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of December 31, 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
The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue.
Performance Obligations
As of December 31, 2022, we have future performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers. Therefore, an obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date. These obligations total $480 million, $316 million, $224 million, $111 million and $63 million that will be recognized in the years ending December 31, 2023, 2024, 2025, 2026 and 2027, respectively, and $672 million thereafter. Capacity revenues are recognized as capacity is made available to the related ISOs/RTOs or counterparties.
Accounts Receivable
The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Trade accounts receivable from contracts with customers — net | $ | 1,644 | | | $ | 1,087 | |
| Other trade accounts receivable — net | 415 | | | 310 | |
| Total trade accounts receivable — net | $ | 2,059 | | | $ | 1,397 | |
5.GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
The following table provides information regarding our goodwill balance.
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| | |
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| Balance at December 31, 2019 | | $ | 2,553 | |
| 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 | |
As of December 31, 2022, the carrying value of goodwill totaled $2.583 billion and consisted of the following:
•$1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.
•$175 million arose in connection with the Merger, of which $122 million was allocated to our Texas Generation reporting unit and $53 million was allocated to our Retail reporting unit. None of the goodwill related to the Merger is deductible for tax purposes.
•$243 million of goodwill arose in connection with the Crius Transaction and was allocated entirely to our Retail reporting unit. None of the goodwill related to the Crius Transaction is deductible for tax purposes.
•$258 million of goodwill arose in connection with the Ambit Transaction and was allocated entirely to our Retail reporting unit. The goodwill related to the Ambit Transaction is deductible for tax purposes over 15 years on a straight-line basis.
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, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates and changes in reporting unit book value.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
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| | December 31, 2022 | | December 31, 2021 |
| Identifiable Intangible Asset | | Gross
Carrying
Amount | | Accumulated
Amortization | | Net | | Gross
Carrying
Amount | | Accumulated
Amortization | | Net |
| Retail customer relationship | | $ | 2,088 | | | $ | 1,768 | | | $ | 320 | | | $ | 2,083 | | | $ | 1,631 | | | $ | 452 | |
| Software and other technology-related assets | | 475 | | | 258 | | | 217 | | | 421 | | | 206 | | | 215 | |
| Retail and wholesale contracts | | 233 | | | 209 | | | 24 | | | 248 | | | 206 | | | 42 | |
| Contractual service agreements (a) | | 18 | | | 4 | | | 14 | | | 23 | | | 2 | | | 21 | |
| Other identifiable intangible assets (b) | | 50 | | | 8 | | | 42 | | | 95 | | | 20 | | | 75 | |
| Total identifiable intangible assets subject to amortization | | $ | 2,864 | | | $ | 2,247 | | | 617 | | | $ | 2,870 | | | $ | 2,065 | | | 805 | |
| Retail trade names (not subject to amortization) (c) | | | | | | 1,341 | | | | | | | 1,341 | |
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| Total identifiable intangible assets | | | | | | $ | 1,958 | | | | | | | $ | 2,146 | |
____________
(a)As of December 31, 2022 and 2021, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization.
(b)Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).
(c)During the year ended December 31, 2021, we recorded a $33 million impairment to a retail trade name intangible asset.
Identifiable intangible liabilities are comprised of the following:
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| | Year Ended December 31, |
| Identifiable Intangible Liability | | 2022 | | 2021 |
Contractual service agreements | | $ | 128 | | | $ | 125 | |
Purchase and sale of power and capacity | | 3 | | | 8 | |
| Fuel and transportation purchase contracts | | 9 | | | 14 | |
| Total identifiable intangible liabilities | | $ | 140 | | | $ | 147 | |
Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of:
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| Identifiable Intangible Assets and Liabilities | | Consolidated Statements of Operations | | Remaining useful lives of identifiable intangible assets at December 31,
2022 (weighted average in years) | | Year Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| Retail customer relationship | | Depreciation and amortization | | 3 | | $ | 137 | | | $ | 197 | | | $ | 283 | |
| Software and other technology-related assets | | Depreciation and amortization | | 4 | | 69 | | | 74 | | | 73 | |
| Retail and wholesale contracts/purchase and sale/fuel and transportation contracts | | Operating revenues/fuel, purchased power costs and delivery fees | | 3 | | 7 | | | (56) | | | 17 | |
| Other identifiable intangible assets | | Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization | | 4 | | 391 | | | 279 | | | 223 | |
| 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. Amounts exclude contractual services agreements. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.
The following is a description of the separately identifiable intangible assets. In connection with fresh start reporting, the Merger, the Crius Transaction and the Ambit Transaction, the intangible assets were adjusted based on their estimated fair value as of the Effective Date, the Merger Date, the Crius Acquisition Date and the Ambit Acquisition Date, respectively, based on observable prices or estimates of fair value using valuation models.
•Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.
•Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization. These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to 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. The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date, the Merger Date, the Crius Acquisition Date or the Ambit Acquisition Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. 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 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.
Estimated Amortization of Identifiable Intangible Assets and Liabilities
As of December 31, 2022, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.
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| Year | | Estimated Amortization Expense |
| 2023 | | $ | 158 | |
| 2024 | | $ | 109 | |
| 2025 | | $ | 82 | |
| 2026 | | $ | 57 | |
| 2027 | | $ | 33 | |
6.INCOME TAXES
Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
Income Tax Expense (Benefit)
The components of our income tax expense (benefit) are as follows:
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| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Current: | | | | | |
| U.S. Federal | $ | 2 | | | $ | 1 | | | $ | (5) | |
| State | 7 | | | 16 | | | 41 | |
| Total current | 9 | | | 17 | | | 36 | |
| Deferred: | | | | | |
| U.S. Federal | (304) | | | (336) | | | 171 | |
| State | (55) | | | (139) | | | 59 | |
| Total deferred | (359) | | | (475) | | | 230 | |
| Total | $ | (350) | | | $ | (458) | | | $ | 266 | |
Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:
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| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Income (loss) before income taxes | $ | (1,560) | | | $ | (1,722) | | | $ | 890 | |
| U.S. federal statutory rate | 21 | % | | 21 | % | | 21 | % |
| Income taxes at the U.S. federal statutory rate | (328) | | | (362) | | | 187 | |
| Nondeductible TRA accretion | 18 | | | (8) | | | (7) | |
| State tax, net of federal benefit | (19) | | | (2) | | | 32 | |
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| Federal and State return to provision adjustment | (15) | | | (2) | | | 13 | |
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| Nondeductible compensation | 5 | | | 4 | | | — | |
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| Equity awards | (3) | | | 1 | | | — | |
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| Valuation allowance on state NOLs | (8) | | | (94) | | | 41 | |
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| Lignite depletion | (4) | | | (3) | | | (3) | |
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| Other | 4 | | | 8 | | | 3 | |
| Income tax expense (benefit) | $ | (350) | | | $ | (458) | | | $ | 266 | |
| Effective tax rate | 22.4 | % | | 26.6 | % | | 29.9 | % |
Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2022 and 2021 are as follows:
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| December 31, |
| 2022 | | 2021 |
| Noncurrent Deferred Income Tax Assets | | | |
| Tax credit carryforwards | $ | 125 | | | $ | 76 | |
| Loss carryforwards | 1,182 | | | 1,193 | |
| | | |
| Identifiable intangible assets | 456 | | | 346 | |
| Long-term debt | 121 | | | 15 | |
| Employee benefit obligations | 108 | | | 121 | |
| Commodity contracts and interest rate swaps | 764 | | | 238 | |
| Other | 49 | | | 148 | |
| Total deferred tax assets | $ | 2,805 | | | $ | 2,137 | |
| Noncurrent Deferred Income Tax Liabilities | | | |
| Property, plant and equipment | 1,033 | | | 767 | |
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| Total deferred tax liabilities | 1,033 | | | 767 | |
| Valuation allowance | 63 | | | 68 | |
| Net Deferred Income Tax Asset | $ | 1,709 | | | $ | 1,302 | |
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. 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.
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
In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. The CARES Act provides numerous relief provisions for corporate taxpayers, including modification of the utilization limitations on net operating losses, favorable expansion of the deduction for business interest expense under IRC Section 163(j) (Section 163(j)), the ability to accelerate timing of refundable AMT credits and the temporary suspension of certain payment requirements for the employer portion of social security taxes. 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. 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
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial for the years ended December 31, 2022, 2021 and 2020. The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets for the years ended December 31, 2022, 2021 and 2020.
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| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Balance at beginning of period, excluding interest and penalties | $ | 38 | | | $ | 39 | | | $ | 126 | |
| | | | | |
| Additions based on tax positions related to prior years | — | | | 1 | | | 3 | |
| Reductions based on tax positions related to prior years | (1) | | | — | | | (90) | |
| | | | | |
| Settlements with taxing authorities | (1) | | | (2) | | | — | |
| | | | | |
| Balance at end of period, excluding interest and penalties | $ | 36 | | | $ | 38 | | | $ | 39 | |
Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities. In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019 and an employment tax audit for tax year 2018. 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
On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.
Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.
Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off.
Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.
7.TAX RECEIVABLE AGREEMENT OBLIGATION
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. federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien secured creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Such TRA Rights are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 18).
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2022, 2021 and 2020.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| TRA obligation at the beginning of the period | $ | 395 | | | $ | 450 | | | $ | 455 | |
| Accretion expense | 64 | | | 62 | | | 64 | |
| Changes in tax assumptions impacting timing of payments (a) | 64 | | | (115) | | | (69) | |
| | | | | |
| Impacts of Tax Receivable Agreement | 128 | | | (53) | | | (5) | |
| Payments | (1) | | | (2) | | | — | |
| TRA obligation at the end of the period | 522 | | | 395 | | | 450 | |
| Less amounts due currently | (8) | | | (1) | | | (3) | |
| Noncurrent TRA obligation at the end of the period | $ | 514 | | | $ | 394 | | | $ | 447 | |
____________
(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. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21%, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra now operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. The estimates of future business results include assumptions related to renewable development projects that Vistra is planning to execute that generate significant tax benefits. These benefits have a material impact on the timing of TRA obligation payments. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of December 31, 2022, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be paid during the next 15 years, and the final payment expected to be made around the year 2056 (if the TRA is not terminated earlier pursuant to its terms).
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. 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.
8.EARNINGS PER SHARE
Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Net income (loss) attributable to Vistra | $ | (1,227) | | | $ | (1,274) | | | $ | 636 | |
| Less cumulative dividends attributable to Series A Preferred Stock | (80) | | | (17) | | | — | |
| Less cumulative dividends attributable to Series B Preferred Stock | (70) | | | (4) | | | — | |
| Net income (loss) attributable to common stock — basic | (1,377) | | | (1,295) | | | 636 | |
| Weighted average shares of common stock outstanding — basic | 422,447,074 | | | 482,214,544 | | | 488,668,263 | |
| Net income (loss) per weighted average share of common stock outstanding — basic | $ | (3.26) | | | $ | (2.69) | | | $ | 1.30 | |
| Dilutive securities: Stock-based incentive compensation plan | — | | | — | | | 2,422,205 | |
| Weighted average shares of common stock outstanding — diluted | 422,447,074 | | | 482,214,544 | | | 491,090,468 | |
| Net income (loss) per weighted average share of common stock outstanding — diluted | $ | (3.26) | | | $ | (2.69) | | | $ | 1.30 | |
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 8,292,647, 14,412,299 and 12,553,414 shares for the years ended December 31, 2022, 2021 and 2020, respectively.
9.ACCOUNTS RECEIVABLE FINANCING
Accounts Receivable Securitization Program
TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). In December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and TriEagle Energy, as originators, and increase the commitment of the Purchasers to $500 million for the remaining term of the Receivables Facility. In February 2021, the Receivables Facility was amended to allow for a one-time, $596 million borrowing to take advantage of a higher receivable balance at such time. The borrowing limit returned to $500 million in March 2021. In March 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $600 million through the July 2021 renewal. The Receivables Facility was renewed in July 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. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limits described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. 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.
Repurchase Facility
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. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Transactions). Each Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.
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 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.
10.DEBT
Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company.
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Vistra Operations Credit Facilities | $ | 2,514 | | | $ | 2,543 | |
| Vistra Operations Senior Secured Notes: | | | |
4.875% Senior Secured Notes, due May 13, 2024 | 400 | | | — | |
3.550% Senior Secured Notes, due July 15, 2024 | 1,500 | | | 1,500 | |
5.125% Senior Secured Notes, due May 13, 2025 | 1,100 | | | — | |
3.700% Senior Secured Notes, due January 30, 2027 | 800 | | | 800 | |
4.300% Senior Secured Notes, due July 15, 2029 | 800 | | | 800 | |
| Total Vistra Operations Senior Secured Notes | 4,600 | | | 3,100 | |
| Vistra Operations Senior Unsecured Notes: | | | |
5.500% Senior Unsecured Notes, due September 1, 2026 | 1,000 | | | 1,000 | |
5.625% Senior Unsecured Notes, due February 15, 2027 | 1,300 | | | 1,300 | |
5.000% Senior Unsecured Notes, due July 31, 2027 | 1,300 | | | 1,300 | |
4.375% Senior Unsecured Notes, due May 15, 2029 | 1,250 | | | 1,250 | |
| Total Vistra Operations Senior Unsecured Notes | 4,850 | | | 4,850 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Other: | | | |
| Forward Capacity Agreements | — | | | 213 | |
| Equipment Financing Agreements | 79 | | | 92 | |
| | | |
| Other | — | | | 6 | |
| Total other long-term debt | 79 | | | 311 | |
| Unamortized debt premiums, discounts and issuance costs | (72) | | | (73) | |
| Total long-term debt including amounts due currently | 11,971 | | | 10,731 | |
| Less amounts due currently | (38) | | | (254) | |
| Total long-term debt less amounts due currently | $ | 11,933 | | | $ | 10,477 | |
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. In April 2021, Vistra Operations borrowed an additional $250 million principal amount under the Term Loan A Facility. Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding under the Revolving Credit Facility. Borrowings under the Term Loan A Facility were reported in short-term borrowings in our 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 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.
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.
Our credit facilities and related available capacity at December 31, 2022 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | December 31, 2022 |
| Credit Facilities | | Maturity Date | | Facility
Limit | | Cash
Borrowings | | Letters of Credit Outstanding | | Available
Capacity |
| 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 | |
| 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.
(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 Non-Extended 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.
The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.
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 (or, during a collateral suspension period, not to exceed 5.50 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. As of December 31, 2022, Vistra has entered into the following series of interest rate swap transactions.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Notional Amount | | Expiration Date | | Rate Range |
| Swapped to fixed | | $3,000 | | July 2023 | | 3.67 | % | - | 3.91% |
| Swapped to variable | | $700 | | July 2023 | | 3.20 | % | - | 3.23% |
| Swapped to fixed | | $720 | | February 2024 | | 3.71 | % | - | 3.72% |
| Swapped to variable | | $720 | | February 2024 | | 3.20 | % | - | 3.20% |
| 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. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.
Secured Letter of Credit Facilities
In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that are each secured by a first lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are used for general corporate purposes. In October 2021, 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.
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 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. The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior, unsecured long-term debt securities obtain an investment grade rating from two out of the three rating agencies, subject to reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt securities or downgrade such rating below investment grade. The Vistra Operations Senior Secured Indenture contains 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.
Vistra Operations Senior Unsecured Notes
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. 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 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 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
On the Merger Date, Vistra assumed $6.138 billion principal amount of Dynegy's senior unsecured notes (Vistra Senior Unsecured Notes). 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.
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.
Other Long-Term Debt
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 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.
Maturities
Long-term debt maturities at December 31, 2022 are as follows:
| | | | | |
| December 31, 2022 |
| 2023 | $ | 40 | |
| 2024 | 1,940 | |
| 2025 | 3,567 | |
| 2026 | 1,006 | |
| 2027 | 3,402 | |
| Thereafter | 2,088 | |
| Unamortized premiums, discounts and debt issuance costs | (72) | |
| Total long-term debt, including amounts due currently | $ | 11,971 | |
11.LEASES
Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 35 years. Our leases include options to renew up to 15 years. Certain leases also contain options to terminate the lease.
Lease Cost
The following table presents costs related to lease activities:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Operating lease cost | $ | 9 | | | $ | 11 | | | $ | 14 | |
| Finance lease: | | | | | |
| Finance lease right-of-use asset amortization | 9 | | | 9 | | | 7 | |
| Interest on lease liabilities | 12 | | | 10 | | | 7 | |
| Total finance lease cost | 21 | | | 19 | | | 14 | |
| Variable lease cost (a) | 22 | | | 29 | | | 29 | |
| Short-term lease cost | 47 | | | 35 | | | 31 | |
| Sublease income (b) | — | | | (7) | | | (8) | |
| Net lease cost | $ | 99 | | | $ | 87 | | | $ | 80 | |
____________
(a)Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used.
(b)Represents sublease income related to real estate leases.
Balance Sheet Information
The following table presents lease related balance sheet information:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Lease assets: | | | |
| Operating lease right-of-use assets | $ | 51 | | | $ | 40 | |
| Finance lease right-of-use assets (net of accumulated depreciation) | 173 | | | $ | 173 | |
| Total lease right-of-use assets | 224 | | | 213 | |
| Current lease liabilities: | | | |
| Operating lease liabilities | 8 | | | 5 | |
| Finance lease liabilities | 9 | | | 8 | |
| Total current lease liabilities | 17 | | | 13 | |
| Noncurrent lease liabilities: | | | |
| Operating lease liabilities | 45 | | | 38 | |
| Finance lease liabilities | 237 | | | 235 | |
| Total noncurrent lease liabilities | 282 | | | 273 | |
| Total lease liabilities | $ | 299 | | | $ | 286 | |
Cash Flows and Other Information
The following table presents lease related cash flows and other information:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
| Operating cash flows from operating leases | $ | 11 | | | $ | 11 | | | $ | 17 | |
| Operating cash flows from finance leases | 8 | | | 9 | | | 5 | |
| Finance cash flows from finance leases | 12 | | | 5 | | | 10 | |
| Non-cash disclosure upon commencement of new lease: | | | | | |
| Right-of-use assets obtained in exchange for new operating lease liabilities | 19 | | | 7 | | | 14 | |
| Right-of-use assets obtained in exchange for new finance lease liabilities | 6 | | | — | | | 108 | |
| Non-cash disclosure upon modification of existing lease: | | | | | |
| Modification of operating lease right-of-use assets | — | | | (4) | | | (1) | |
| Modification of finance lease right-of-use assets | 4 | | | (1) | | | 23 | |
Weighted Average Remaining Lease Term
The following table presents weighted average remaining lease term information:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Weighted average remaining lease term: | | | |
| Operating lease | 15.8 years | | 17.6 years |
| Finance lease | 24.2 years | | 25.0 years |
| Weighted average discount rate: | | | |
| Operating lease | 6.26% | | 5.76 | % |
| Finance lease | 4.81% | | 4.95 | % |
Maturity of Lease Liabilities
The following table presents maturity of lease liabilities:
| | | | | | | | | | | | | | | | | |
| Operating Lease | | Finance Lease | | Total Lease |
| 2023 | $ | 10 | | | $ | 21 | | | $ | 31 | |
| 2024 | 7 | | | 20 | | | 27 | |
| 2025 | 6 | | | 20 | | | 26 | |
| 2026 | 4 | | | 14 | | | 18 | |
| 2027 | 4 | | | 13 | | | 17 | |
| Thereafter | 57 | | | 358 | | | 415 | |
| Total lease payments | 88 | | | 446 | | | 534 | |
| Less: Interest | (35) | | | (200) | | | (235) | |
| Present value of lease liabilities | $ | 53 | | | $ | 246 | | | $ | 299 | |
12.COMMITMENTS AND CONTINGENCIES
Contractual Commitments
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
Contracts |
| 2023 | $ | 285 | | | $ | 76 | | | $ | 146 | | | | | $ | 9 | |
| 2024 | 250 | | | 33 | | | 136 | | | | | 9 | |
| 2025 | 187 | | | 34 | | | 120 | | | | | 9 | |
| 2026 | 242 | | | 35 | | | 106 | | | | | 9 | |
| 2027 | 141 | | | 36 | | | 89 | | | | | 9 | |
| Thereafter | 2,318 | | | — | | | 132 | | | | | 50 | |
| Total | $ | 3,423 | | | $ | 214 | | | $ | 729 | | | | | $ | 95 | |
____________
(a)Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company.
In addition to the commitments detailed above, we have nuclear fuel contracts with early termination penalties. As of December 31, 2022, termination costs of $65 million would be incurred if we terminated those contracts.
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.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.
Letters of Credit
As of December 31, 2022, we had outstanding letters of credit totaling $2.651 billion as follows:
•$2.314 billion to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;
•$180 million to support battery and solar development projects;
•$27 million to support executory contracts and insurance agreements;
•$74 million to support our REP financial requirements with the PUCT; and
•$56 million for other credit support requirements.
Surety Bonds
As of December 31, 2022, we had outstanding surety bonds totaling $932 million to support performance under various contracts and legal obligations in the normal course of business.
Litigation and Regulatory Proceedings
Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. 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.
Litigation
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. 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
Repricing Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of wholesale power prices during load-shedding events. We filed our opening brief in June 2021, and response briefs were filed in September 2021. 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. Other parties also filed briefs in support of our challenge to the PUCT's orders. In addition, we have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with the Third Court of Appeals that 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. Koch subsequently filed its own related lawsuit in Delaware Chancery Court, and the Delaware Chancery Court ruled that all claims related to the APA dispute (including our equitable claims) would proceed in Delaware. We contested Koch's demand for $286 million for the February 2021 earnout payment as an unjust windfall and inconsistent with the parties' intent when they entered into the APA in 2017. 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 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, 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, 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 that repealed the Clean Power Plan (CPP) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. 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 NOX 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 SIP and a partial FIP. For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NOX, 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. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are in compliance with the rule, and the retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply. The 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. Circuit Court have been held in abeyance pending the EPA's action on reconsideration.
SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. In 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 May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, 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 SO2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduces emission limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval.
Effluent Limitation Guidelines (ELGs)
In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. 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. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. In July 2021, the EPA announced its intent to revise the ELG rule and moved to hold the 2020 ELG revision litigation in abeyance pending the EPA's completion of its reconsideration rulemaking. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021.
CCR/Groundwater
In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned for review of this rule in the D.C. Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities. In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake. 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 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. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.
At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. 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 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 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 is currently abated.
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. 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. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule 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 and five of our sites in July 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 required 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 approved by the IEPA. However, the currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabilities, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.
MISO 2015-2016 Planning Resource Auction
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. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants. 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 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, 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, 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. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020. In August 2021, the D.C. 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. The D.C. 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 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
We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Labor Contracts
We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, 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.
Nuclear Insurance
Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination and accidental premature decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.
With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $13.7 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $13.7 billion limit for a single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facility resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).
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 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. Assessments are currently limited to $20.5 million per operating licensed reactor per year per incident. As of December 31, 2022, our maximum potential assessment under the industry retrospective plan would be approximately $275 million per incident but no more than $41 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $450 million per accident at any nuclear facility.
The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion (subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per accident), above which we are self-insured.
We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service for more than twelve weeks as a result of covered direct physical damage. Such coverage provides for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $3.6 million for the remaining 71 weeks. The total maximum coverage is $328 million for non-nuclear property damage and $490 million for nuclear property damage. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.
13.EQUITY
Common Stock Issuances and Repurchases
Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2022, 2021 and 2020 are reflected in the table below.
| | | | | | | | | | | | | | | | | |
| Shares
Issued | | Treasury
Shares | | Shares Outstanding |
| Balance at December 31, 2019 | 528,741,335 | | | (41,043,224) | | | 487,698,111 | |
| Shares issued (a) | 1,611,462 | | | — | | | 1,611,462 | |
| Shares retired | (3,685) | | | — | | | (3,685) | |
| | | | | |
| Balance at December 31, 2020 | 530,349,112 | | | (41,043,224) | | | 489,305,888 | |
| Shares issued (a) | 2,583,761 | | | — | | | 2,583,761 | |
| 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 | |
| Shares issued (a) | 4,262,575 | | | — | | | 4,262,575 | |
| Shares retired | (12,979) | | | — | | | (12,979) | |
| 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)Shares repurchased include 78,087 and 5,174,863 of unsettled shares purchased as of December 31, 2022 and 2021, respectively.
Share Repurchase Programs
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. 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 and the certificate of designation of the Series A Preferred Stock and the Series B Preferred Stock, respectively.
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 described above in October 2021.
Preferred Stock
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 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering). The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.
The Series A Preferred Stock and the Series B Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights. The Series A Preferred Stock may be redeemed at the option of the Company at any time after the Series A First Reset Date (defined below) and in certain other circumstances prior to the Series A First Reset Date. The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date.
Dividends
Common Stock Dividends — In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations. Quarterly dividends 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 | | 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. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07%), plus a spread of 6.93% per annum. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board.
The annual dividend rate on each share of Series B Preferred Stock is 7.0% from the Series B Issuance Date to, but excluding December 15, 2026 (Series B First Reset Date). On and after the Series B First Reset Date, the dividend rate on each share of Series B Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.26%), plus a spread of 5.74% per annum. The Series B Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series B Preferred Stock are payable semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board.
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 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 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.
Accumulated Other Comprehensive Income
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, 2022, 2021 and 2020, zero, $(8) million and $(5) million respectively was reclassified from accumulated other comprehensive income and reported in other deductions.
Warrants
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 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.
14.FAIR VALUE MEASUREMENTS
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Chief Financial Officer.
Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 15 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
•Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that are legally characterized as settlement of derivative contracts rather than collateral.
•Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.
•Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company's risk management group.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement.
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | December 31, 2021 |
| Level
1 | | Level
2 | | Level
3 (a) | | Reclass (b) | | Total | | Level
1 | | Level
2 | | Level
3 (a) | | Reclass (b) | | Total |
| Assets: | | | | | | | | | | | | | | | | | | | |
| Commodity contracts | $ | 3,512 | | | $ | 789 | | | $ | 791 | | | $ | 13 | | | $ | 5,105 | | | $ | 1,408 | | | $ | 889 | | | $ | 442 | | | $ | 5 | | | $ | 2,744 | |
| Interest rate swaps | — | | | 135 | | | — | | | — | | | 135 | | | — | | | 19 | | | — | | | — | | | 19 | |
| Nuclear decommissioning trust – equity securities (c) | 532 | | | — | | | — | | | — | | | 532 | | | 724 | | | — | | | — | | | — | | | 724 | |
| Nuclear decommissioning trust – debt securities (c) | — | | | 658 | | | — | | | — | | | 658 | | | — | | | 679 | | | — | | | — | | | 679 | |
| Sub-total | $ | 4,044 | | | $ | 1,582 | | | $ | 791 | | | $ | 13 | | | 6,430 | | | $ | 2,132 | | | $ | 1,587 | | | $ | 442 | | | $ | 5 | | | 4,166 | |
| Assets measured at net asset value (d): | | | | | | | | | | | | | | | | | | | |
| Nuclear decommissioning trust – equity securities (c) | | | | | | | | | 458 | | | | | | | | | | | 557 | |
| Total assets | | | | | | | | | $ | 6,888 | | | | | | | | | | | $ | 4,723 | |
| Liabilities: | | | | | | | | | | | | | | | | | | | |
| Commodity contracts | $ | 5,297 | | | $ | 933 | | | $ | 2,010 | | | $ | 13 | | | $ | 8,253 | | | $ | 2,153 | | | $ | 650 | | | $ | 802 | | | $ | 5 | | | $ | 3,610 | |
| Interest rate swaps | — | | | 83 | | | — | | | — | | | 83 | | | — | | | 217 | | | — | | | — | | | 217 | |
| Total liabilities | $ | 5,297 | | | $ | 1,016 | | | $ | 2,010 | | | $ | 13 | | | $ | 8,336 | | | $ | 2,153 | | | $ | 867 | | | $ | 802 | | | $ | 5 | | | $ | 3,827 | |
____________
(a)See table below for description of Level 3 assets and liabilities.
(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 investments line in our consolidated balance sheets. See Note 20.
(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 NPNS. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 15 for further discussion regarding derivative instruments.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at December 31, 2022 and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2022 |
| | Fair Value | | | | | | | | | | |
| Contract Type (a) | | Assets | | Liabilities | | Total | | Valuation Technique | | Significant Unobservable Input | | Range (b) | | Average (b) |
| Electricity purchases and sales | | $ | 603 | | | $ | (1,332) | | | $ | (729) | | | Income Approach | | Hourly price curve shape (c) | | $ | — | | to | $ | 80 | | | $ | 38 | |
| | | | | | | | | MWh |
| | | | | | | | | | Illiquid delivery periods for hub power prices and heat rates (d) | | $ | 25 | | to | $ | 95 | | | $ | 60 | |
| | | | | | | | | | | MWh |
| Options | | — | | | (483) | | | (483) | | | Option Pricing Model | | Gas to power correlation (e) | | 10 | % | to | 100 | % | | 56 | % |
| | | | | | | | Power and gas volatility (e) | | 5 | % | to | 620 | % | | 313 | % |
| Financial transmission rights | | 132 | | | (31) | | | 101 | | | Market Approach (f) | | Illiquid price differences between settlement points (g) | | $ | (35) | | to | $ | 10 | | | $ | (11) | |
| | | | | | | | | MWh |
| Natural gas | | 20 | | | (155) | | | (135) | | | Income Approach | | Gas basis and illiquid delivery periods (h) | | $ | — | | to | $ | 30 | | | $ | 13 | |
| | | | | | | | | MMBtu |
| Coal | | 21 | | | (1) | | | 20 | | | Income Approach | | Probability of default (i) | | — | % | to | 40 | % | | 20% |
| | | | | | | | Recovery rate (j) | | — | % | to | 40 | % | | 20% |
| | | | | | | | | | | | | | | | |
| Other (k) | | 15 | | | (8) | | | 7 | | | | | | | | | | | |
| Total | | $ | 791 | | | $ | (2,010) | | | $ | (1,219) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 |
| | Fair Value | | | | | | | | | | |
| Contract Type (a) | | Assets | | Liabilities | | Total | | Valuation Technique | | Significant Unobservable Input | | Range (b) | | Average (b) |
| Electricity purchases and sales | | $ | 204 | | | $ | (470) | | | $ | (266) | | | Income Approach | | Hourly price curve shape (c) | | $ | — | | to | $ | 60 | | | $ | 30 | |
| | | | | | | | | MWh | | |
| | | | | | | | | | Illiquid delivery periods for hub power prices and heat rates (d) | | $ | 20 | | to | $ | 140 | | | $ | 80 | |
| | | | | | | | | | | MWh | | |
| Options | | 1 | | | (209) | | | (208) | | | Option Pricing Model | | Gas to power correlation (e) | | 10 | % | to | 100 | % | | 56 | % |
| | | | | | | | Power and gas volatility (e) | | 5 | % | to | 490 | % | | 248 | % |
| Financial transmission rights | | 122 | | | (34) | | | 88 | | | Market Approach (f) | | Illiquid price differences between settlement points (g) | | $ | (30) | | to | $ | 10 | | | $ | (9) | |
| | | | | | | | | MWh | | |
| Natural gas | | 29 | | | (86) | | | (57) | | | Income Approach | | Gas basis (h) | | $ | (1) | | to | $ | 16 | | | $ | 8 | |
| | | | | | | | | MMBtu |
| Coal | | 61 | | | — | | | 61 | | | Income Approach | | Probability of default (i) | | — | % | to | 40 | % | | 20% |
| | | | | | | | Recovery rate (j) | | — | % | to | 40 | % | | 20% |
| | | | | | | | | | | | | | | | |
| Other (k) | | 25 | | | (3) | | | 22 | | | | | | | | | | | |
| Total | | $ | 442 | | | $ | (802) | | | $ | (360) | | | | | | | | | | | |
____________
(a)Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions. Options consist of physical electricity options, spread options, swaptions and natural gas options.
(b)The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.
(c)Primarily based on the historical range of forward average hourly ERCOT North Hub prices.
(d)Primarily based on historical forward ERCOT and PJM power prices and ERCOT heat rate variability.
(e)Primarily based on the historical forward correlation and volatility within ERCOT and PJM.
(f)While we use the market approach, there is insufficient market data to consider the valuation liquid.
(g)Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h)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.
(j)Estimate of the default recovery rate based on historical corporate rates.
(k)Other includes contracts for environmental allowances.
There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2022, 2021 and 2020. See the table below for discussion of transfers between Level 2 and Level 3 for the years ended December 31, 2022, 2021 and 2020.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the years ended December 31, 2022, 2021 and 2020.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Net asset (liability) balance at beginning of period | $ | (360) | | | $ | 22 | | | $ | (74) | |
| Total unrealized valuation losses (a) | (1,382) | | | (53) | | | (5) | |
| Purchases, issuances and settlements (b): | | | | | |
| Purchases | 185 | | | 114 | | | 164 | |
| Issuances | (62) | | | (36) | | | (28) | |
| Settlements | 345 | | | (314) | | | (90) | |
| Transfers into Level 3 (c) | (30) | | | (2) | | | (2) | |
| Transfers out of Level 3 (c) | 85 | | | (91) | | | 57 | |
| | | | | |
| | | | | |
| Net change (d) | (859) | | | (382) | | | 96 | |
| Net asset (liability) balance at end of period | $ | (1,219) | | | $ | (360) | | | $ | 22 | |
| Unrealized valuation gains (losses) relating to instruments held at end of period | $ | (977) | | | $ | (364) | | | $ | 18 | |
____________
(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. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.
(c)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 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 are reported as operating revenues in our consolidated statements of operations.
15.COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 14 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets and to hedge future purchased power costs for our retail operations. We also utilize short-term electricity, natural gas, coal and emissions derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our consolidated statements of operations in operating revenues and fuel, purchased power costs and delivery fees.
Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our consolidated statements of operations in interest expense and related charges. 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. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our consolidated balance sheets at December 31, 2022 and 2021. 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 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 |
| Derivative Assets | | Derivative Liabilities | | |
| Commodity Contracts | | Interest Rate Swaps | | Commodity Contracts | | Interest Rate Swaps | | Total |
| Current assets | $ | 4,442 | | | $ | 92 | | | $ | 4 | | | $ | — | | | $ | 4,538 | |
| Noncurrent assets | 656 | | | 43 | | | 3 | | | — | | | 702 | |
| Current liabilities | (1) | | | — | | | (6,562) | | | (47) | | | (6,610) | |
| Noncurrent liabilities | (5) | | | — | | | (1,685) | | | (36) | | | (1,726) | |
| Net assets (liabilities) | $ | 5,092 | | | $ | 135 | | | $ | (8,240) | | | $ | (83) | | | $ | (3,096) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 |
| Derivative Assets | | Derivative Liabilities | | |
| Commodity Contracts | | Interest Rate Swaps | | Commodity Contracts | | Interest Rate Swaps | | Total |
| Current assets | $ | 2,496 | | | $ | 14 | | | $ | 3 | | | $ | — | | | $ | 2,513 | |
| Noncurrent assets | 244 | | | 5 | | | 1 | | | — | | | 250 | |
| Current liabilities | — | | | — | | | (2,964) | | | (59) | | | (3,023) | |
| Noncurrent liabilities | (1) | | | — | | | (645) | | | (158) | | | (804) | |
| Net assets (liabilities) | $ | 2,739 | | | $ | 19 | | | $ | (3,605) | | | $ | (217) | | | $ | (1,064) | |
As of December 31, 2022 and 2021, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pre-tax effect of derivative gains (losses) on net income, including realized and unrealized effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| Derivative (consolidated statements of operations presentation) | 2022 | | 2021 | | 2020 |
| Commodity contracts (Operating revenues) | $ | (4,103) | | | $ | (1,196) | | | $ | 241 | |
| Commodity contracts (Fuel, purchased power costs and delivery fees) | 375 | | | 732 | | | 4 | |
| Interest rate swaps (Interest expense and related charges) | 234 | | | 81 | | | (196) | |
| Net gain (loss) | $ | (3,494) | | | $ | (383) | | | $ | 49 | |
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.
Generally, margin deposits that contractually offset these derivative instruments are reported separately in our consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.
The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 | | December 31, 2021 |
| | Derivative Assets
and Liabilities | | Offsetting Instruments (a) | | Cash Collateral (Received) Pledged (b) | | Net Amounts | | Derivative Assets
and Liabilities | | Offsetting Instruments (a) | | Cash Collateral (Received) Pledged (b) | | Net Amounts |
| Derivative assets: | | | | | | | | | | | | | | | | |
| Commodity contracts | | $ | 5,092 | | | $ | (4,480) | | | $ | (20) | | | $ | 592 | | | $ | 2,739 | | | $ | (2,051) | | | $ | (27) | | | $ | 661 | |
| Interest rate swaps | | 135 | | | (64) | | | — | | | 71 | | | 19 | | | (19) | | | — | | | — | |
| Total derivative assets | | 5,227 | | | (4,544) | | | (20) | | | 663 | | | 2,758 | | | (2,070) | | | (27) | | | 661 | |
| Derivative liabilities: | | | | | | | | | | | | | | | | |
| Commodity contracts | | (8,240) | | | 4,480 | | | 1,675 | | | (2,085) | | | (3,605) | | | 2,051 | | | 784 | | | (770) | |
| Interest rate swaps | | (83) | | | 64 | | | — | | | (19) | | | (217) | | | 19 | | | — | | | (198) | |
| Total derivative liabilities | | (8,323) | | | 4,544 | | | 1,675 | | | (2,104) | | | (3,822) | | | 2,070 | | | 784 | | | (968) | |
| Net amounts | | $ | (3,096) | | | $ | — | | | $ | 1,655 | | | $ | (1,441) | | | $ | (1,064) | | | $ | — | | | $ | 757 | | | $ | (307) | |
____________
(a)Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at December 31, 2022 and 2021:
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 | | December 31, 2021 | | |
| Derivative type | | Notional Volume | | Unit of Measure |
| Natural gas (a) | | 6,007 | | | 4,701 | | | Million MMBtu |
| Electricity | | 754,762 | | | 440,236 | | | GWh |
| Financial transmission rights (b) | | 225,845 | | | 224,876 | | | GWh |
| Coal | | 48 | | | 25 | | | Million U.S. tons |
| Fuel oil | | 105 | | | 87 | | | Million gallons |
| | | | | | |
| Emissions | | 40 | | | 18 | | | Million tons |
| Renewable energy certificates | | 31 | | | 32 | | | Million certificates |
| Interest rate swaps – variable/fixed (c) | | $ | 6,720 | | | $ | 6,720 | | | Million U.S. dollars |
| Interest rate swaps - fixed/variable (c) | | $ | 2,120 | | | $ | 2,120 | | | Million U.S. dollars |
____________
(a)Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.
(b)Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions.
(c)Includes notional amounts of interest rate swaps with maturity dates through July 2026.
Credit Risk-Related Contingent Features of Derivatives
Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Fair value of derivative contract liabilities (a) | $ | (1,934) | | | $ | (1,200) | |
| Offsetting fair value under netting arrangements (b) | 899 | | | 660 | |
| Cash collateral and letters of credit | 253 | | | 95 | |
| Liquidity exposure | $ | (782) | | | $ | (445) | |
____________
(a)Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).
(b)Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. 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 $1.064 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.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
16.PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS
Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist entirely of participants who were active and retired collective bargaining unit employees. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations.
Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.
Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts for its interest in this OPEB plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the OPEB information presented below. In addition, Vistra is the sponsor of OPEB plans that certain EFH Corp. and Dynegy retirees participate in.
Pension and OPEB Costs
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Pension costs | $ | 2 | | | $ | 6 | | | $ | 11 | |
| OPEB costs | 4 | | | 8 | | | 7 | |
| Total benefit costs recognized as expense | $ | 6 | | | $ | 14 | | | $ | 18 | |
Market-Related Value of Assets Held in Pension Benefit Trusts
We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
Detailed Information Regarding Pension Plans and OPEB Benefits
The following information is based on a December 31, 2022, 2021 and 2020 measurement dates:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Retirement Plan | | OPEB Plans |
| Year Ended December 31, | | Year Ended December 31, |
| 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Assumptions Used to Determine Net Periodic Pension and Benefit Cost: | | | | | | | | | | | |
| Discount rate | 2.84 | % | | 2.50 | % | | 3.24 | % | | 2.87 | % | | 2.51 | % | | 3.25 | % |
| Expected rate of compensation increase | 3.49 | % | | 3.41 | % | | 3.29 | % | | | | | | |
| Interest crediting rate for cash balance | 3.00 | % | | 3.00 | % | | 3.50 | % | | | | | | |
| Expected return on plan assets (Vistra Plan) | 4.24 | % | | 3.77 | % | | 4.44 | % | | | | | | |
| Expected return on plan assets (Dynegy Plan) | 4.77 | % | | 4.42 | % | | 5.28 | % | | | | | | |
| Expected return on plan assets (EEI Plan) | 4.92 | % | | 4.72 | % | | 5.45 | % | | | | | | |
| Expected return on plan assets (EEI Union) | | | | | | | 3.92 | % | | 6.79 | % | | 7.07 | % |
| Expected return on plan assets (EEI Salaried) | | | | | | | 3.41 | % | | 2.95 | % | | 3.43 | % |
| Components of Net Pension and Benefit Cost: | | | | | | | | | | | |
| Service cost | $ | 4 | | | $ | 5 | | | $ | 6 | | | $ | 1 | | | $ | 1 | | | $ | 2 | |
| Interest cost | 17 | | | 16 | | | 20 | | | 4 | | | 4 | | | 4 | |
| Expected return on assets | (19) | | | (18) | | | (23) | | | (1) | | | (2) | | | (2) | |
| Amortization of unrecognized amounts, net | — | | | 3 | | | 1 | | | — | | | 5 | | | 4 | |
| Immediate pension and postretirement benefit cost | — | | | — | | | 7 | | | — | | | — | | | (1) | |
| Net periodic pension and OPEB cost | $ | 2 | | | $ | 6 | | | $ | 11 | | | $ | 4 | | | $ | 8 | | | $ | 7 | |
| Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: | | | | | | | | | | | |
| 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 | |
| Assumptions Used to Determine Benefit Obligations at Period End: | | | | | | | | | | | |
| Discount rate | 5.16 | % | | 2.84 | % | | 2.50 | % | | 5.18 | % | | 2.87 | % | | 2.51 | % |
| Expected rate of compensation increase | 3.79 | % | | 3.49 | % | | 3.41 | % | | | | | | |
| Interest crediting rate for cash balance plans | 3.00 | % | | 3.00 | % | | 3.00 | % | | | | | | |
Net Actuarial Gains (Losses)
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.
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 | |
| Year Ended December 31, | | Year Ended December 31, | |
| 2022 | | 2021 | | 2022 | | 2021 | |
| Change in Pension and Postretirement Benefit Obligations: | | | | | | | | |
| Projected benefit obligation at beginning of period | $ | 605 | | | $ | 643 | | | $ | 146 | | | $ | 157 | | |
| | | | | | | | |
| Service cost | 4 | | | 5 | | | 1 | | | 1 | | |
| Interest cost | 17 | | | 16 | | | 4 | | | 4 | | |
| | | | | | | | |
| Participant contributions | — | | | — | | | 2 | | | 3 | | |
| Plan amendments | 9 | | | — | | | — | | | — | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Actuarial gain | (113) | | | (11) | | | (30) | | | (6) | | |
| | | | | | | | |
| Benefits paid | (73) | | | (48) | | | (13) | | | (13) | | |
| Projected benefit obligation at end of year | $ | 449 | | | $ | 605 | | | $ | 110 | | | $ | 146 | | |
| Accumulated benefit obligation at end of year | $ | 447 | | | $ | 600 | | | $ | — | | | $ | — | | |
| Change in Plan Assets: | | | | | | | | |
| Fair value of assets at beginning of period | $ | 470 | | | $ | 485 | | | $ | 39 | | | $ | 37 | | |
| | | | | | | | |
| | | | | | | | |
| Employer contributions | — | | | 1 | | | 9 | | | 9 | | |
| Participant contributions | — | | | — | | | 2 | | | 3 | | |
| | | | | | | | |
| | | | | | | | |
| Actual gain (loss) on assets | (77) | | | 30 | | | (6) | | | 3 | | |
| | | | | | | | |
| Transfers | — | | | — | | | (2) | | | — | | |
| Benefits paid | (73) | | | (46) | | | (13) | | | (13) | | |
| Fair value of assets at end of year | $ | 320 | | | $ | 470 | | | $ | 29 | | | $ | 39 | | |
| Funded Status: | | | | | | | | |
| Projected pension benefit obligation | $ | (449) | | | $ | (605) | | | $ | (110) | | | $ | (146) | | |
| Fair value of assets | 320 | | | 470 | | | 29 | | | 39 | | |
| Funded status at end of year | $ | (129) | | | $ | (135) | | | $ | (81) | | | $ | (107) | | |
| Amounts Recognized in the Balance Sheet Consist of: | | | | | | | | |
| | | | | | | | |
| Investments | $ | — | | | $ | — | | | $ | 20 | | | $ | 26 | | |
| Other current liabilities | — | | | — | | | (8) | | | (9) | | |
| Other noncurrent liabilities | (129) | | | (135) | | | (93) | | | (124) | | |
| Net liability recognized | $ | (129) | | | $ | (135) | | | $ | (81) | | | $ | (107) | | |
| 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, 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:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Asset Category: | | | |
| Interest-bearing cash (a) | $ | 2 | | | $ | — | |
| Cash commingled trusts | 4 | | | 11 | |
| Equity securities: | | | |
| Global equities | 80 | | | 149 | |
| | | |
| | | |
| Fixed income securities: | | | |
| Corporate bonds (b) | 107 | | | 199 | |
| Government bonds | 44 | | | 31 | |
| Other (c) | 24 | | | 30 | |
| Real estate | 43 | | | 50 | |
| Hedge funds | 16 | | | — | |
| Total assets measured at net asset value | $ | 320 | | | $ | 470 | |
___________
(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.
(c)Consists primarily of high-yield bonds, emerging market debt and bank loans.
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.
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Pension Plans with PBO and ABO in Excess of Plan Assets: | | | |
| Projected benefit obligations | $ | 449 | | | $ | 605 | |
| Accumulated benefit obligation | $ | 447 | | | $ | 600 | |
| Plan assets | $ | 320 | | | $ | 470 | |
Retirement Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets. 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Target Allocation Ranges |
| Asset Category: | Vistra Plan | | Dynegy Plan | | |
| Fixed income | 50 | % | - | 70% | | 44 | % | - | 54% | | | | |
| Global equity securities | 20 | % | - | 28% | | 26 | % | - | 36% | | | | |
| Real estate | 6 | % | - | 10% | | 8 | % | - | 12% | | | | |
| Credit strategies | 2 | % | | 6% | | 3 | % | - | 7% | | | | |
| Hedge funds | 2 | % | - | 6% | | 3 | % | - | 7% | | | | |
Retirement Plan Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
| | | | | | | | | | | | | |
| Retirement Plan |
| Expected Long-Term Rate of Return |
| Asset Class: | Vistra Plan | | Dynegy Plan | | |
| Fixed income securities | 5.2 | % | | 5.1 | % | | |
| Global equity securities | 7.9 | % | | 7.9 | % | | |
| Real estate | 4.8 | % | | 4.8 | % | | |
| Credit strategies | 7.0 | % | | 7.0 | % | | |
| Hedge funds | 7.5 | % | | 7.5 | % | | |
| Weighted average | 5.8 | % | | 5.8 | % | | |
Benefit Plan Assumed Health Care Cost Trend Rates
The following tables provide information regarding the assumed health care cost trend rates.
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Assumed Health Care Cost Trend Rates-Not Medicare Eligible: | | | |
| Health care cost trend rate assumed for next year | 6.80 | % | | 6.30 | % |
| Rate to which the cost trend is expected to decline (the ultimate trend rate) | 4.50 | % | | 4.50 | % |
| Year that the rate reaches the ultimate trend rate | 2032 | | 2029 |
| Assumed Health Care Cost Trend Rates-Medicare Eligible: | | | |
| Health care cost trend rate assumed for next year (Vistra Plan, EEI Union and EEI Salaried) | 10.30 | % | | 9.60 | % |
| Health care cost trend rate assumed for next year (Split-Participant Plan) | 10.00 | % | | 8.90 | % |
| Rate to which the cost trend is expected to decline (the ultimate trend rate) | 4.50 | % | | 4.50 | % |
| Year that the rate reaches the ultimate trend rate | 2032 | | 2031 |
Significant Concentrations of Risk
The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2022 consisted of 504 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings.
Contributions
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.
Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2028-2032 |
| Pension benefits | $ | 80 | | | $ | 30 | | | $ | 30 | | | $ | 36 | | | $ | 33 | | | $ | 143 | |
| OPEB | $ | 10 | | | $ | 10 | | | $ | 9 | | | $ | 9 | | | $ | 8 | | | $ | 38 | |
Qualified Savings Plans
Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the traditional formula in the Retirement Plan) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.
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.
17.STOCK-BASED COMPENSATION
Vistra 2016 Omnibus Incentive Plan
On the Effective Date, the Vistra board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019 annual meeting of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards.
If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date.
As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders.
Stock-Based Compensation Expense
Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Total stock-based compensation expense | $ | 65 | | | $ | 51 | | | $ | 63 | |
| Income tax benefit | (15) | | | (12) | | | (15) | |
| Stock based-compensation expense, net of tax | $ | 50 | | | $ | 39 | | | $ | 48 | |
Stock Options
The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model. The risk-free interest rate used in the option valuation model was based on yields available on the grant dates for U.S. Treasury Strips with maturity consistent with the expected life assumption. The expected term of the option represents the period of time that options granted are expected to be outstanding and is based on the SEC Simplified Method (midpoint of average vesting time and contractual term). 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 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. The following table summarizes our stock option activity:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| Stock Options
(in thousands) | | Weighted
Average Exercise Price | | Weighted Average Remaining Contractual Term (Years) | | Aggregate Intrinsic Value (in millions) |
| Total outstanding at beginning of period | 13,947 | | | $ | 19.28 | | | 5.9 | | $ | 55.7 | |
| | | | | | | |
| | | | | | | |
| Exercised | (2,763) | | | $ | 15.65 | | | | | |
| Forfeited or expired | (266) | | | $ | 23.96 | | | | | |
| Total outstanding at end of period | 10,918 | | | $ | 20.10 | | | 5.1 | | $ | 39.2 | |
| Exercisable at December 31, 2022 | 7,914 | | | $ | 19.92 | | | 5.1 | | $ | 31.4 | |
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
The following table summarizes our restricted stock unit activity:
| | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| Restricted Stock Units
(in thousands) | | Weighted
Average Grant Date Fair Value | | | | |
| Total nonvested at beginning of period | 2,811 | | | $ | 22.57 | | | | | |
| | | | | | | |
| Granted | 2,197 | | | $ | 21.16 | | | | | |
| Vested | (1,192) | | | $ | 23.38 | | | | | |
| Forfeited | (201) | | | $ | 21.72 | | | | | |
| Total nonvested at end of period | 3,615 | | | $ | 21.49 | | | | | |
| | | | | | | |
As of December 31, 2022, $46 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years.
We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a three year performance period and a payout opportunity of 0-200% of target (100%), which is intended to be settled in shares of Vistra common stock. We recognized compensation expense associated with PSUs of $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.
18.RELATED PARTY TRANSACTIONS
In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRA) with certain selling stockholders. Pursuant to the RRA, we maintain a registration statement on Form S-3 providing for registration of the resale of the Vistra common stock held by such selling stockholders. In addition, under the terms of the RRA, among other things, if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the RRA the opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.
Tax Receivable Agreement
On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH. See Note 7 for discussion of the TRA.
19.SEGMENT INFORMATION
The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.
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. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources.
The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 states in the U.S.
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 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 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 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 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, 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. GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
For the year ended | | Retail | | Texas | | East | | West | | Sunset | | Asset Closure | | Corporate and Other (b) | | Eliminations | | Consolidated |
| Operating revenues (a): | | |
| December 31, 2022 | | $ | 9,455 | | | $ | 3,733 | | | $ | 3,706 | | | $ | 336 | | | $ | 956 | | | $ | 296 | | | $ | 1 | | | $ | (4,755) | | | $ | 13,728 | |
| December 31, 2021 | | 7,871 | | | 2,790 | | | 2,587 | | | 374 | | | 653 | | | 86 | | | — | | | (2,284) | | | 12,077 | |
| December 31, 2020 | | 8,270 | | | 4,116 | | | 2,415 | | | 282 | | | 936 | | | 319 | | | — | | | (4,895) | | | 11,443 | |
| Depreciation and amortization: | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | $ | (145) | | | $ | (537) | | | $ | (706) | | | $ | (42) | | | $ | (76) | | | $ | (21) | | | $ | (69) | | | $ | — | | | $ | (1,596) | |
| December 31, 2021 | | (212) | | | (608) | | | (698) | | | (60) | | | (104) | | | (35) | | | (36) | | | — | | | (1,753) | |
| December 31, 2020 | | (303) | | | (475) | | | (721) | | | (19) | | | (109) | | | (46) | | | (64) | | | — | | | (1,737) | |
| Operating income (loss): | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | $ | 1,172 | | | $ | (711) | | | $ | (867) | | | $ | (250) | | | $ | (256) | | | $ | (130) | | | $ | (135) | | | $ | — | | | $ | (1,177) | |
| December 31, 2021 | | 2,213 | | | (2,601) | | | (552) | | | (8) | | | (143) | | | (341) | | | (83) | | | — | | | (1,515) | |
| December 31, 2020 | | 312 | | | 1,761 | | | 73 | | | 39 | | | (246) | | | (283) | | | (137) | | | — | | | 1,519 | |
| Interest expense and related charges: | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | $ | (14) | | | $ | 20 | | | $ | (3) | | | $ | 6 | | | $ | (3) | | | $ | (3) | | | $ | (371) | | | $ | — | | | $ | (368) | |
| December 31, 2021 | | (9) | | | 14 | | | (15) | | | 9 | | | (3) | | | — | | | (381) | | | 1 | | | (384) | |
| December 31, 2020 | | (10) | | | 8 | | | (7) | | | 10 | | | (1) | | | (1) | | | (632) | | | 3 | | | (630) | |
| Income tax (expense) benefit: | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 350 | | | $ | — | | | $ | 350 | |
| December 31, 2021 | | (2) | | | — | | | — | | | — | | | — | | | — | | | 460 | | | — | | | 458 | |
| December 31, 2020 | | — | | | — | | | — | | | — | | | — | | | — | | | (266) | | | — | | | (266) | |
| Net income (loss): | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | $ | 1,158 | | | $ | (615) | | | $ | (868) | | | $ | (238) | | | $ | (258) | | | $ | (119) | | | $ | (270) | | | $ | — | | | $ | (1,210) | |
| December 31, 2021 | | 2,196 | | | (2,512) | | | (567) | | | 1 | | | (137) | | | (298) | | | 53 | | | — | | | (1,264) | |
| December 31, 2020 | | 309 | | | 1,760 | | | 41 | | | 50 | | | (245) | | | (270) | | | (1,021) | | | — | | | 624 | |
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures: |
| December 31, 2022 | | $ | 1 | | | $ | 335 | | | $ | 56 | | | $ | 116 | | | $ | 33 | | | $ | — | | | $ | 55 | | | $ | — | | | $ | 596 | |
| December 31, 2021 | | 1 | | | 266 | | | 44 | | | 8 | | | 28 | | | 3 | | | 48 | | | — | | | 398 | |
| December 31, 2020 | | 2 | | | 388 | | | 71 | | | 2 | | | 34 | | | 12 | | | 91 | | | — | | | 600 | |
____________
(a)The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended | | Retail (1) | | Texas | | East | | West | | Sunset | | Asset Closure | | Corporate and Other | | Eliminations (2) | | Consolidated |
| December 31, 2022 | | $ | (532) | | | $ | (1,472) | | | $ | (757) | | | $ | (324) | | | $ | (3) | | | $ | 106 | | | $ | — | | | $ | 819 | | | $ | (2,163) | |
| December 31, 2021 | | (325) | | | (1,272) | | | (637) | | | (42) | | | (444) | | | (190) | | | — | | | 1,719 | | | (1,191) | |
| December 31, 2020 | | (11) | | | 677 | | | (23) | | | (10) | | | (122) | | | (18) | | | — | | | (329) | | | 164 | |
____________
(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).
20.SUPPLEMENTARY FINANCIAL INFORMATION
Impairment of Long-Lived Assets
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 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 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
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Interest paid/accrued | $ | 591 | | | $ | 480 | | | $ | 467 | |
| Unrealized mark-to-market net (gains) losses on interest rate swaps | (250) | | | (134) | | | 155 | |
| Amortization of debt issuance costs, discounts and premiums | 28 | | | 30 | | | 18 | |
| Debt extinguishment (gain) loss | (1) | | | 1 | | | (17) | |
| Capitalized interest | (29) | | | (26) | | | (21) | |
| Other | 29 | | | 33 | | | 28 | |
| Total interest expense and related charges | $ | 368 | | | $ | 384 | | | $ | 630 | |
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 4.30%, 3.90% and 3.88% as of December 31, 2022, 2021 and 2020, respectively.
Other Income and Deductions
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Other income: | | | | | |
| Insurance settlements (a) | $ | 70 | | | $ | 88 | | | $ | 6 | |
| Gain on settlement of rail transportation disputes (b) | — | | | 15 | | | — | |
| Sale of land (b) | 8 | | | 9 | | | 8 | |
| | | | | |
| | | | | |
| | | | | |
| Interest income | 19 | | | — | | | 2 | |
| | | | | |
| All other | 20 | | | 28 | | | 18 | |
| Total other income | $ | 117 | | | $ | 140 | | | $ | 34 | |
| Other deductions: | | | | | |
| | | | | |
| | | | | |
| 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, 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.
(b)Reported in the Asset Closure segment.
(c)Reported in the East segment.
Restricted Cash
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | December 31, 2021 |
| Current
Assets | | Noncurrent Assets | | Current
Assets | | Noncurrent Assets |
| Amounts related to remediation escrow accounts | $ | 37 | | | $ | 33 | | | $ | 21 | | | $ | 13 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total restricted cash | $ | 37 | | | $ | 33 | | | $ | 21 | | | $ | 13 | |
Remediation Escrow — During the years ended December 31, 2022, 2020 and 2019, Vistra transferred asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra deposits funds into an escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.
Trade Accounts Receivable
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Wholesale and retail trade accounts receivable | $ | 2,124 | | | $ | 1,442 | |
| Allowance for uncollectible accounts | (65) | | | (45) | |
| Trade accounts receivable — net | $ | 2,059 | | | $ | 1,397 | |
Gross trade accounts receivable as of December 31, 2022 and 2021 included unbilled retail revenues of $607 million and $426 million, respectively.
Allowance for Uncollectible Accounts Receivable
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Allowance for uncollectible accounts receivable at beginning of period (a) | $ | 45 | | | $ | 45 | | | $ | 42 | |
| Increase for bad debt expense | 179 | | | 110 | | | 110 | |
| Decrease for account write-offs | (159) | | | (110) | | | (107) | |
| Allowance for uncollectible accounts receivable at end of period | $ | 65 | | | $ | 45 | | | $ | 45 | |
____________
(a)The beginning balance in 2020 includes a $6 million increase recorded due to the adoption of ASU 2016-13, Financial Instruments—Credit Losses (see Note 1).
Inventories by Major Category
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Materials and supplies | $ | 274 | | | $ | 260 | |
| Fuel stock | 252 | | | 314 | |
| Natural gas in storage | 44 | | | 36 | |
| Total inventories | $ | 570 | | | $ | 610 | |
Investments
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Nuclear plant decommissioning trust | $ | 1,648 | | | $ | 1,960 | |
| Assets related to employee benefit plans (Note 16) | 30 | | | 42 | |
| Land | 41 | | | 44 | |
| Miscellaneous other | 10 | | | 3 | |
| Total investments | $ | 1,729 | | | $ | 2,049 | |
Investment in Unconsolidated Subsidiary
On the Merger Date, we assumed Dynegy's 50% interest in NELP, a joint venture with NextEra Energy, Inc., which indirectly owned the Bellingham NEA facility and the Sayreville facility.
In December 2019, Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., indirect subsidiaries of Vistra, entered into a transaction agreement with NELP and certain indirect subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP in exchange for 100% ownership interest in NJEA, the company which owns the Sayreville facility. The NELP Transaction was approved by FERC in February 2020, and the NELP Transaction closed on March 2, 2020. As a result of the NELP Transaction, Vistra indirectly owns 100% of the Sayreville facility and no longer has any ownership interest in the Bellingham NEA facility. A loss of $29 million was recognized in connection with the NELP Transaction, reflecting the difference between our derecognized investment in NELP and the value of our acquired 100% interest in NJEA, which was measured in accordance with ASC 805. The loss is reported in our consolidated statements of operations in other deductions.
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
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. 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 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. A summary of the fair market value of investments in the fund follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | Year Ended December 31, |
| | | | | | | 2022 | | 2021 |
| Debt securities (a) | | | | | | | $ | 658 | | | $ | 679 | |
| Equity securities (b) | | | | | | | 990 | | | 1,281 | |
| Total | | | | | | | $ | 1,648 | | | $ | 1,960 | |
____________
(a)The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. 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 2.64% 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. equity investments and the MSCI EAFE Index for non-U.S. equity investments.
Debt securities held as of December 31, 2022 mature as follows: $246 million in one to five years, $159 million in five to 10 years and $253 million after 10 years.
The following table summarizes proceeds from sales of securities and investments in new securities.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| | | | | |
| | | | | |
| Proceeds from sales of securities | $ | 670 | | | $ | 483 | | | $ | 433 | |
| Investments in securities | $ | (693) | | | $ | (505) | | | $ | (455) | |
Property, Plant and Equipment
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Power generation and structures | $ | 16,597 | | | $ | 16,195 | |
| Land | 584 | | | 608 | |
| Office and other equipment | 163 | | | 183 | |
| Total | 17,344 | | | 16,986 | |
| Less accumulated depreciation | (5,753) | | | (4,801) | |
| Net of accumulated depreciation | 11,591 | | | 12,185 | |
| Finance lease right-of-use assets (net of accumulated depreciation) | 173 | | | 173 | |
Nuclear fuel (net of accumulated amortization of $152 million and $125 million) | 268 | | | 212 | |
| Construction work in progress | 522 | | | 486 | |
| Property, plant and equipment — net | $ | 12,554 | | | $ | 13,056 | |
Depreciation expenses totaled $1.388 billion, $1.478 billion and $1.377 billion for the years ended December 31, 2022, 2021 and 2020, respectively.
Our property, plant and equipment consist of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful lives range from 1 to 31 years for our property, plant and equipment.
Asset Retirement and Mining Reclamation Obligations (ARO)
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. 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, 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, 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:
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Plant Decommissioning | | Mining Land Reclamation | | Coal Ash and Other | | Total |
| Liability at December 31, 2019 | $ | 1,320 | | | $ | 410 | | | $ | 508 | | | $ | 2,238 | |
| Additions: | | | | | | | |
| Accretion | 46 | | | 20 | | | 23 | | | 89 | |
| Adjustment for change in estimates (a) | 219 | | | (6) | | | 25 | | | 238 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Reductions: | | | | | | | |
| Payments | — | | | (65) | | | (49) | | | (114) | |
| Liability transfers (b) | — | | | — | | | (15) | | | (15) | |
| | | | | | | |
| Liability at December 31, 2020 | 1,585 | | | 359 | | | 492 | | | 2,436 | |
| Additions: | | | | | | | |
| Accretion | 50 | | | 16 | | | 22 | | | 88 | |
| Adjustment for change in estimates | — | | | 13 | | | 1 | | | 14 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Reductions: | | | | | | | |
| Payments | — | | | (68) | | | (20) | | | (88) | |
| | | | | | | |
| | | | | | | |
| Liability at December 31, 2021 | 1,635 | | | 320 | | | 495 | | | 2,450 | |
| Additions: | | | | | | | |
| Accretion | 53 | | | 14 | | | 20 | | | 87 | |
| Adjustment for change in estimates | — | | | 22 | | | 27 | | | 49 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Reductions: | | | | | | | |
| Payments | — | | | (70) | | | (18) | | | (88) | |
| Liability transfers (b) | — | | | (2) | | | (59) | | | (61) | |
| | | | | | | |
| Liability at December 31, 2022 | 1,688 | | | 284 | | | 465 | | | 2,437 | |
| Less amounts due currently | — | | | (105) | | | (23) | | | (128) | |
| Noncurrent liability at December 31, 2022 | $ | 1,688 | | | $ | 179 | | | $ | 442 | | | $ | 2,309 | |
____________
(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. The increase in the liability was driven by changes in assumptions including increased costs for labor, equipment and services and a delay in timing of when the U.S. 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
The balance of other noncurrent liabilities and deferred credits consists of the following:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Retirement and other employee benefits (Note 16) | $ | 237 | | | $ | 276 | |
| Winter Storm Uri impact (a) | 35 | | | 261 | |
| Identifiable intangible liabilities (Note 5) | 140 | | | 147 | |
| Regulatory liability (b) | — | | | 325 | |
| Finance lease liabilities | 237 | | | 235 | |
| Uncertain tax positions, including accrued interest | 13 | | | 13 | |
| Liability for third-party remediation | 37 | | | 17 | |
| | | |
| Accrued severance costs | 36 | | | 39 | |
| Other accrued expenses | 269 | | | 176 | |
| Total other noncurrent liabilities and deferred credits | $ | 1,004 | | | $ | 1,489 | |
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(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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | December 31, 2022 | | December 31, 2021 |
| Long-term debt (see Note 10): | | Fair Value Hierarchy | | Carrying Amount | | Fair
Value | | Carrying Amount | | Fair
Value |
| Long-term debt under the Vistra Operations Credit Facilities | | Level 2 | | $ | 2,519 | | | $ | 2,486 | | | $ | 2,549 | | | $ | 2,518 | |
| Vistra Operations Senior Notes | | Level 2 | | 9,378 | | | 8,830 | | | 7,880 | | | 8,193 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Forward Capacity Agreements | | Level 3 | | — | | | — | | | 211 | | | 211 | |
| Equipment Financing Agreements | | Level 3 | | 74 | | | 72 | | | 85 | | | 85 | |
| | | | | | | | | | |
| Building Financing | | Level 2 | | — | | | — | | | 3 | | | 3 | |
| | | | | | | | | | |
| Other debt | | Level 3 | | — | | | — | | | 3 | | | 3 | |
We determine fair value in accordance with accounting standards as discussed in Note 14. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.
Supplemental Cash Flow Information
The following table reconciles cash, cash equivalents and restricted cash reported in our consolidated statements of cash flows to the amounts reported in our consolidated balance sheets at December 31, 2022 and 2021:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Cash and cash equivalents | $ | 455 | | | $ | 1,325 | |
| Restricted cash included in current assets | 37 | | | 21 | |
| Restricted cash included in noncurrent assets | 33 | | | 13 | |
| Total cash, cash equivalents and restricted cash | $ | 525 | | | $ | 1,359 | |
The following summarizes our supplemental cash flow information for the years ended December 31, 2022, 2021 and 2020, respectively.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Cash payments related to: | | | | | |
| Interest paid | $ | 581 | | | $ | 482 | | | $ | 503 | |
| Capitalized interest | (29) | | | (26) | | | (21) | |
| Interest paid (net of capitalized interest) | $ | 552 | | | $ | 456 | | | $ | 482 | |
| | | | | |
| Noncash investing and financing activities: | | | | | |
| Accrued property, plant and equipment additions (a) | $ | 103 | | | $ | 171 | | | $ | 19 | |
| Disposition of investment in NELP | $ | — | | | $ | — | | | $ | 123 | |
| Acquisition of investment in NJEA | $ | — | | | $ | — | | | $ | 90 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
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(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.