NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.
Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 16 for further information concerning 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. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows. 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. The final financial impact of Winter Storm Uri continues to be subject to the completion of customer billing activities, receipt of final settlement data from ERCOT, the outcome of potential litigation arising from the event, or any corrective action taken by the State of Texas, ERCOT, the RCT or the PUCT to resettle pricing across any portion of the supply chain (i.e. fuel supply, wholesale pricing of generation, or allocating the financial impacts of market-wide load shed ratably across all retail market participants), that is currently being considered or may be considered by any such parties. Additionally, we have disputes over certain gas invoices that are not anticipated to have a material impact.
COVID-19 Pandemic
In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and the U.S. Government declared the COVID-19 outbreak a national emergency. The U.S. government has deemed electricity generation, transmission and distribution as “critical infrastructure” providing essential services during this global emergency. As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations.
The Company's condensed consolidated financial statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impact of COVID-19 on the assumptions and estimates used and determined that there have been no material adverse impacts on the Company's results of operations for the three months ended March 31, 2021.
In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. See Note 6 for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.
Basis of Presentation
The condensed 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 2020 Form 10-K. The condensed consolidated financial information herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal nature. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our 2020 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. 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.
2. DEVELOPMENT OF GENERATION FACILITIES
Texas Segment Solar Generation and Energy Storage Projects
In September 2020, we announced the planned development of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. Estimated commercial operation dates for these facilities range from Summer 2021 to Fall 2022. At March 31, 2021, we had accumulated approximately $96 million in construction-work-in-process for these Texas segment solar generation and battery ESS projects.
West Segment Energy Storage Projects
Oakland — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California. 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). PG&E filed its application with the CPUC in June 2018 and the CPUC approved the resource adequacy contract in November 2018. At March 31, 2021, we had accumulated approximately $412 million in construction work-in-process for Moss Landing Phase I. Under the contract, PG&E will pay us a fixed monthly resource adequacy payment, while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. PG&E filed for Chapter 11 bankruptcy protection in January 2019. In November 2019, the bankruptcy court approved PG&E's motion requesting approval of the assumption of the resource adequacy contract subject to the CPUC approving the terms of an amendment to the resource adequacy contract, and the CPUC approved the terms of the amendment in January 2020. PG&E emerged from bankruptcy protection in July 2020. Moss Landing Phase I completed capacity testing in April 2021 to begin providing full capacity to PG&E as required by the resource adequacy contract and participating in the CAISO energy market.
In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10-year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II). PG&E filed its application with the CPUC in May 2020 and the CPUC approved the resource adequacy contract in August 2020. At March 31, 2021, we had accumulated approximately $54 million in construction work-in-process for Moss Landing Phase II. We anticipate Moss Landing Phase II will commence commercial operations in the third quarter of 2021.
3. RETIREMENT OF GENERATION FACILITIES
In December 2020, we announced the retirement of our 83 MW Wharton natural gas facility in Texas due to its age, cost profile and small scale, as well as low power prices, limited operational windows and substantial costs to repair, maintain and upgrade the facility. The previously announced retirement of our 244 MW Trinidad natural gas facility in Texas was rescinded in April 2021.
In September and December 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 11), and in furtherance of our efforts to significantly reduce our carbon footprint. In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022, three years earlier than previously disclosed, in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018 (see Note 11). Expected plant retirement expenses of $43 million, driven by severance cost, were accrued in the three months ended September 30, 2020 in operating costs of our Sunset segment. Operational results for plants with planned retirements are included in our Sunset segment beginning in the quarter when a retirement plan is announced. See Note 17 for discussion of impairments recorded in connection with these announcements.
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|
|
|
|
|
|
|
|
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|
|
Name
|
|
Location
|
|
ISO/RTO
|
|
Fuel Type
|
|
Net Generation Capacity (MW)
|
|
Expected Retirement Date (a)
|
|
Baldwin
|
|
Baldwin, IL
|
|
MISO
|
|
Coal
|
|
1,185
|
|
By the end of 2025
|
|
Coleto Creek
|
|
Goliad, TX
|
|
ERCOT
|
|
Coal
|
|
650
|
|
By the end of 2027
|
|
Joppa
|
|
Joppa, IL
|
|
MISO
|
|
Coal
|
|
802
|
|
By September 1, 2022
|
|
Joppa
|
|
Joppa, IL
|
|
MISO
|
|
Natural Gas
|
|
221
|
|
By September 1, 2022
|
|
Kincaid
|
|
Kincaid, IL
|
|
PJM
|
|
Coal
|
|
1,108
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|
By the end of 2027
|
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Miami Fort
|
|
North Bend, OH
|
|
PJM
|
|
Coal
|
|
1,020
|
|
By the end of 2027
|
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Newton
|
|
Newton, IL
|
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MISO/PJM
|
|
Coal
|
|
615
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By the end of 2027
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Zimmer
|
|
Moscow, OH
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PJM
|
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Coal
|
|
1,300
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By the end of 2027
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Total
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|
|
|
|
|
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6,901
|
|
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____________
(a)Generation facilities may retire earlier than expected dates if economic or other conditions dictate.
4. REVENUE
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|
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|
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|
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Three Months Ended March 31, 2021
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|
|
Retail
|
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Texas
|
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East
|
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West
|
|
Sunset
|
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Asset
Closure
|
|
Eliminations
|
|
Consolidated
|
|
Revenue from contracts with customers:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Retail energy charge in ERCOT
|
$
|
1,149
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,149
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|
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Retail energy charge in Northeast/Midwest
|
586
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|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
586
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|
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Wholesale generation revenue from ISO/RTO
|
—
|
|
|
3,246
|
|
|
156
|
|
|
38
|
|
|
723
|
|
|
—
|
|
|
—
|
|
|
4,163
|
|
|
Capacity revenue from ISO/RTO (a)
|
—
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|
Revenue from other wholesale contracts
|
—
|
|
|
2,028
|
|
|
163
|
|
|
21
|
|
|
58
|
|
|
—
|
|
|
—
|
|
|
2,270
|
|
|
Total revenue from contracts with customers
|
1,735
|
|
|
5,274
|
|
|
315
|
|
|
59
|
|
|
820
|
|
|
—
|
|
|
—
|
|
|
8,203
|
|
|
Other revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Intangible amortization
|
(1)
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(6)
|
|
|
—
|
|
|
—
|
|
|
(6)
|
|
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Hedging and other revenues (b)
|
16
|
|
|
(4,442)
|
|
|
63
|
|
|
(27)
|
|
|
(600)
|
|
|
—
|
|
|
—
|
|
|
(4,990)
|
|
|
Affiliate sales
|
—
|
|
|
251
|
|
|
345
|
|
|
1
|
|
|
65
|
|
|
—
|
|
|
(662)
|
|
|
—
|
|
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Total other revenues
|
15
|
|
|
(4,191)
|
|
|
409
|
|
|
(26)
|
|
|
(541)
|
|
|
—
|
|
|
(662)
|
|
|
(4,996)
|
|
|
Total revenues
|
$
|
1,750
|
|
|
$
|
1,083
|
|
|
$
|
724
|
|
|
$
|
33
|
|
|
$
|
279
|
|
|
$
|
—
|
|
|
$
|
(662)
|
|
|
$
|
3,207
|
|
____________
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes net purchases of capacity in the PJM market and the Sunset segment includes net sales of capacity in the PJM market.
(b)Includes $58 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 16 for unrealized net gains (losses) by segment.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2020
|
|
|
Retail
|
|
Texas
|
|
East
|
|
West
|
|
Sunset
|
|
Asset
Closure
|
|
|
|
Eliminations
|
|
Consolidated
|
|
Revenue from contracts with customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail energy charge in ERCOT
|
$
|
1,253
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
—
|
|
|
$
|
1,253
|
|
|
Retail energy charge in Northeast/Midwest
|
640
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
—
|
|
|
640
|
|
|
Wholesale generation revenue from ISO/RTO
|
—
|
|
|
96
|
|
|
58
|
|
|
33
|
|
|
74
|
|
|
—
|
|
|
|
|
—
|
|
|
261
|
|
|
Capacity revenue from ISO/RTO (a)
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
42
|
|
|
—
|
|
|
|
|
—
|
|
|
45
|
|
|
Revenue from other wholesale contracts
|
—
|
|
|
50
|
|
|
164
|
|
|
4
|
|
|
49
|
|
|
—
|
|
|
|
|
—
|
|
|
267
|
|
|
Total revenue from contracts with customers
|
1,893
|
|
|
146
|
|
|
225
|
|
|
37
|
|
|
165
|
|
|
—
|
|
|
|
|
—
|
|
|
2,466
|
|
|
Other revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible amortization
|
(4)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
|
|
—
|
|
|
(8)
|
|
|
Hedging and other revenues (b)
|
19
|
|
|
248
|
|
|
(25)
|
|
|
44
|
|
|
114
|
|
|
—
|
|
|
|
|
—
|
|
|
400
|
|
|
Affiliate sales
|
—
|
|
|
467
|
|
|
534
|
|
|
1
|
|
|
71
|
|
|
—
|
|
|
|
|
(1,073)
|
|
|
—
|
|
|
Total other revenues
|
15
|
|
|
715
|
|
|
509
|
|
|
45
|
|
|
181
|
|
|
—
|
|
|
|
|
(1,073)
|
|
|
392
|
|
|
Total revenues
|
$
|
1,908
|
|
|
$
|
861
|
|
|
$
|
734
|
|
|
$
|
82
|
|
|
$
|
346
|
|
|
$
|
—
|
|
|
|
|
$
|
(1,073)
|
|
|
$
|
2,858
|
|
____________
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes net purchases of capacity in the PJM market and the Sunset segment includes net sales of capacity in the PJM market.
(b)Includes $201 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 16 for unrealized net gains (losses) by segment.
Performance Obligations
As of March 31, 2021, 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 $663 million, $541 million, $164 million, $141 million and $98 million that will be recognized, in the balance of the year ended December 31, 2021 and the years ending December 31, 2022, 2023, 2024 and 2025, respectively, and $484 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:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31, 2020
|
|
Trade accounts receivable from contracts with customers — net
|
$
|
1,230
|
|
|
$
|
1,169
|
|
|
Other trade accounts receivable — net
|
86
|
|
|
110
|
|
|
Total trade accounts receivable — net
|
$
|
1,316
|
|
|
$
|
1,279
|
|
5. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
At both March 31, 2021 and December 31, 2020, the carrying value of goodwill totaled $2.583 billion, including $2.461 billion allocated to our Retail reporting unit and $122 million allocated to our Texas Generation reporting unit. Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight line basis.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
Identifiable Intangible Asset
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Retail customer relationship
|
|
$
|
2,082
|
|
|
$
|
1,483
|
|
|
$
|
599
|
|
|
$
|
2,082
|
|
|
$
|
1,434
|
|
|
$
|
648
|
|
|
Software and other technology-related assets
|
|
421
|
|
|
198
|
|
|
223
|
|
|
414
|
|
|
186
|
|
|
228
|
|
|
Retail and wholesale contracts
|
|
269
|
|
|
211
|
|
|
58
|
|
|
272
|
|
|
204
|
|
|
68
|
|
|
Contractual service agreements (a)
|
|
41
|
|
|
—
|
|
|
41
|
|
|
51
|
|
|
1
|
|
|
50
|
|
|
Other identifiable intangible assets (b)
|
|
53
|
|
|
20
|
|
|
33
|
|
|
96
|
|
|
19
|
|
|
77
|
|
|
Total identifiable intangible assets subject to amortization
|
|
$
|
2,866
|
|
|
$
|
1,912
|
|
|
954
|
|
|
$
|
2,915
|
|
|
$
|
1,844
|
|
|
1,071
|
|
|
Retail trade names (not subject to amortization)
|
|
|
|
|
|
1,374
|
|
|
|
|
|
|
1,374
|
|
|
Mineral interests (not currently subject to amortization)
|
|
|
|
|
|
1
|
|
|
|
|
|
|
1
|
|
|
Total identifiable intangible assets
|
|
|
|
|
|
$
|
2,329
|
|
|
|
|
|
|
$
|
2,446
|
|
____________
(a)At March 31, 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).
Identifiable intangible liabilities are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable Intangible Liability
|
|
March 31,
2021
|
|
December 31, 2020
|
|
Contractual service agreements
|
|
$
|
128
|
|
|
$
|
129
|
|
|
Purchase and sale of power and capacity
|
|
85
|
|
|
87
|
|
|
Fuel and transportation purchase contracts
|
|
17
|
|
|
73
|
|
|
Total identifiable intangible liabilities
|
|
$
|
230
|
|
|
$
|
289
|
|
Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the condensed consolidated statements of operations) consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable Intangible Assets and Liabilities
|
|
Condensed Consolidated Statements of Operations
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Retail customer relationship
|
|
Depreciation and amortization
|
|
|
|
|
|
$
|
49
|
|
|
$
|
74
|
|
|
Software and other technology-related assets
|
|
Depreciation and amortization
|
|
|
|
|
|
19
|
|
|
17
|
|
|
Retail and wholesale contracts/purchase and sale/fuel and transportation contracts
|
|
Operating revenues/fuel, purchased power costs and delivery fees
|
|
|
|
|
|
8
|
|
|
2
|
|
|
Other identifiable intangible assets
|
|
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
|
|
|
|
|
|
57
|
|
|
52
|
|
|
Total intangible asset expense (a)
|
|
|
|
|
|
$
|
133
|
|
|
$
|
145
|
|
____________
(a)Amounts recorded in depreciation and amortization totaled $68 million and $91 million for the three months ended March 31, 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 condensed 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.
Estimated Amortization of Identifiable Intangible Assets and Liabilities
As of March 31, 2021, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Estimated Amortization Expense
|
|
2021
|
|
$
|
283
|
|
|
2022
|
|
$
|
187
|
|
|
2023
|
|
$
|
131
|
|
|
2024
|
|
$
|
82
|
|
|
2025
|
|
$
|
57
|
|
6. INCOME TAXES
Income Tax Expense
The calculation of our effective tax rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Income (loss) before income taxes
|
|
|
|
|
$
|
(2,525)
|
|
|
$
|
62
|
|
|
Income tax (expense) benefit
|
|
|
|
|
$
|
485
|
|
|
$
|
(17)
|
|
|
Effective tax rate
|
|
|
|
|
19.2
|
%
|
|
27.4
|
%
|
For the three months ended March 31, 2021, the effective tax rate of 19.2% was lower than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.
For the three months ended March 31, 2020, the effective tax rate of 27.4% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.
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 alternative minimum tax (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. Vistra expects to receive an approximate $366 million increase in interest expense deduction in the 2021 tax year under the final Section 163(j) regulations. We do not anticipate a material impact to the effective tax rate from this impact. Vistra is also utilizing the CARES Act payroll deferral mechanism to defer the payment of approximately $20 million from 2020 to 2021 and 2022.
Liability for Uncertain Tax Positions
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. Crius is currently under audit by the IRS for the tax years 2015 and 2016. Uncertain tax positions totaled $39 million at both March 31, 2021 and December 31, 2020.
7. TAX RECEIVABLE AGREEMENT OBLIGATION
On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first-lien creditors of TCEH. 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 15).
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the three months ended March 31, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2021
|
|
2020
|
|
TRA obligation at the beginning of the period
|
$
|
450
|
|
|
$
|
455
|
|
|
Accretion expense
|
17
|
|
|
17
|
|
|
Changes in tax assumptions impacting timing of payments (a)
|
(54)
|
|
|
(9)
|
|
|
Impacts of Tax Receivable Agreement
|
(37)
|
|
|
8
|
|
|
|
|
|
|
|
TRA obligation at the end of the period
|
413
|
|
|
463
|
|
|
Less amounts due currently
|
(3)
|
|
|
—
|
|
|
Noncurrent TRA obligation at the end of the period
|
$
|
410
|
|
|
$
|
463
|
|
____________
(a)During the three months ended March 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $54 million as a result of adjustments to forecasted taxable income due to financial impacts of Winter Storm Uri. During the three months ended March 31, 2020, we recorded a decrease of $9 million to the carrying value of the TRA obligation as a result of adjustments to the timing of forecasted taxable income, including the impacts of the CARES Act and changes to Section 163(j) percentage limitation amount.
As of March 31, 2021, the estimated carrying value of the TRA obligation totaled $413 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. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of March 31, 2021, 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.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Net income (loss) attributable to common stock — basic
|
|
|
|
|
$
|
(2,043)
|
|
|
$
|
56
|
|
|
Weighted average shares of common stock outstanding — basic
|
|
|
|
|
484,699,267
|
|
|
487,944,564
|
|
|
Net income (loss) per weighted average share of common stock outstanding — basic
|
|
|
|
|
$
|
(4.21)
|
|
|
$
|
0.11
|
|
|
Dilutive securities: Stock-based incentive compensation plan
|
|
|
|
|
—
|
|
|
2,694,062
|
|
|
Weighted average shares of common stock outstanding — diluted
|
|
|
|
|
484,699,267
|
|
|
490,638,626
|
|
|
Net income (loss) per weighted average share of common stock outstanding — diluted
|
|
|
|
|
$
|
(4.21)
|
|
|
$
|
0.11
|
|
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 15,254,972 and 10,872,836 shares for the three months ended March 31, 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). The Receivables Facility was renewed in July 2020, extending the term of the Receivables Facility to July 2021, with the ability to borrow $550 million beginning with the settlement date in July 2020 until the settlement date in August 2020, $625 million from the settlement date in August 2020 until the settlement date in November 2020, $550 million from the settlement date in November 2020 until the settlement date in December 2020 and $450 million from the settlement date in December 2020 and thereafter for the remaining term of the Receivables Facility. In December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and TriEagle Energy, as originators, and increase the commitment of the Purchasers to $500 million. In February 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $596 million to take advantage of a higher receivable balance at such time. The commitment of the Purchasers returned to $500 million upon the settlement date in March 2021. In March 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $600 million 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 condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our condensed 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 March 31, 2021, outstanding borrowings under the Receivables Facility totaled $600 million and were supported by $805 million of RecCo gross receivables. As of December 31, 2020, outstanding borrowings under the Receivables Facility totaled $300 million and were supported by $735 million of RecCo gross receivables.
Repurchase Facility
In October 2020, TXU Energy and the other originators under the Receivables Facility entered into a $125 million repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). 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.
As of March 31, 2021, outstanding borrowings under the Repurchase Facility totaled $125 million. There were no outstanding borrowings at December 31, 2020.
10. LONG-TERM DEBT
Amounts in the table below represent the categories of long-term debt obligations incurred by the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Vistra Operations Credit Facilities
|
$
|
2,564
|
|
|
$
|
2,572
|
|
|
Vistra Operations Senior Secured Notes:
|
|
|
|
|
3.550% Senior Secured Notes, due July 15, 2024
|
1,500
|
|
|
1,500
|
|
|
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
|
3,100
|
|
|
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
|
|
|
Total Vistra Operations Senior Unsecured Notes
|
3,600
|
|
|
3,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other:
|
|
|
|
|
Forward Capacity Agreements
|
534
|
|
|
45
|
|
|
Equipment Financing Agreements
|
65
|
|
|
68
|
|
|
8.82% Building Financing due semiannually through February 11, 2022 (a)
|
6
|
|
|
10
|
|
|
Other
|
3
|
|
|
3
|
|
|
Total other long-term debt
|
608
|
|
|
126
|
|
|
Unamortized debt premiums, discounts and issuance costs (b)
|
(80)
|
|
|
(68)
|
|
|
Total long-term debt including amounts due currently
|
9,792
|
|
|
9,330
|
|
|
Less amounts due currently
|
(480)
|
|
|
(95)
|
|
|
Total long-term debt less amounts due currently
|
$
|
9,312
|
|
|
$
|
9,235
|
|
____________
(a)Obligation related to a corporate office space finance lease. This obligation will be funded by amounts held in an escrow account that is reflected in current assets in our condensed consolidated balance sheets.
(b)Includes impact of recording debt assumed in the Merger at fair value.
Vistra Operations Credit Facilities
At March 31, 2021, the Vistra Operations Credit Facilities consisted of up to $6.289 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $2.725 billion, including a $2.35 billion letter of credit sub-facility (Revolving Credit Facility), term loans maturing in 2022 of $1.0 billion (Term Loan A Facility) and term loans maturing in 2025 of $2.564 billion (Term Loan B-3 Facility).
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. The Term Loan A Facility matures on March 28, 2022. 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 are reported in short-term borrowings in our condensed consolidated balance sheet.
In March 2020, Vistra Operations repurchased $100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $93.875 and cancelled them. We recorded an extinguishment gain of $6 million on the transaction in the three months ended March 31, 2020.
During the three months ended March 31, 2021, we borrowed $1.3 billion and repaid $1.0 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes. In April 2021, we repaid the remaining balance under the Revolving Credit Facility.
The Vistra Operations Credit Facilities and related available capacity at March 31, 2021 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
Vistra Operations Credit Facilities
|
|
Maturity Date
|
|
Facility
Limit
|
|
Cash
Borrowings
|
|
Letters of Credit Outstanding
|
|
Available
Capacity
|
|
Revolving Credit Facility (a)
|
|
June 14, 2023
|
|
$
|
2,725
|
|
|
$
|
300
|
|
|
$
|
636
|
|
|
$
|
1,789
|
|
|
Term Loan A Facility (b)
|
|
March 28, 2022
|
|
1,000
|
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
Term Loan B-3 Facility (c)
|
|
December 31, 2025
|
|
2,564
|
|
|
2,564
|
|
|
—
|
|
|
—
|
|
|
Total Vistra Operations Credit Facilities
|
|
|
|
$
|
6,289
|
|
|
$
|
3,864
|
|
|
$
|
636
|
|
|
$
|
1,789
|
|
___________
(a)Revolving Credit Facility to be used for general corporate purposes. The Facility includes a $2.35 billion letter of credit sub-facility. Letters of credit outstanding reduce our available capacity. Cash borrowings under the Revolving Credit Facility are reported in short-term borrowings in our condensed consolidated balance sheets. In April 2021, Vistra Operations repaid the $300 million of cash borrowings.
(b)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. Cash borrowings under the Term Loan A Facility are reported in short-term borrowings in our condensed consolidated balance sheets.
(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.
At March 31, 2021, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were $300 million in outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan A Facility bears interest based on LIBOR rates plus fixed spreads of 1.625%. At March 31, 2021, the weighted average interest rates on outstanding borrowings was 1.73% under the Term Loan A Facility. Amounts borrowed under the Term Loan B-3 Facility bears interest based on applicable LIBOR rates plus fixed spreads of 1.75%. At March 31, 2021, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 1.86% including both the Revolving Credit Facility and the Term Loan B-3 Facility. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the available Revolving Credit Facility.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra Operations Credit Facilities.
The Vistra Operations Credit 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. Although the period ended March 31, 2021 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. 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.
Interest Rate Swaps — Vistra employs interest rate swaps to hedge our exposure to variable rate debt. As of March 31, 2021, 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 2020, Vistra entered into uncommitted standby letter of credit facilities (Secured LOC 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). The facility is to be used for general corporate purposes. At March 31, 2021, $461 million of letters of credit were outstanding under the Secured LOC Facilities.
Alternate Letter of Credit Facility
At March 31, 2021, $250 million of letters of credit were outstanding under a $250 million alternate letter of credit facility. The facility is to be used for general corporate purposes and matures in December 2021.
Vistra Operations Senior Secured Notes
In 2019, Vistra Operations issued and sold $3.1 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 and the 4.300% senior secured notes due 2029 (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 2018 and 2019, Vistra Operations issued and sold $3.6 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 and the 5.000% senior unsecured notes due 2027 (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 April 2020, the Company's board of directors (Board) authorized up to $1.0 billion to repay or repurchase additional outstanding debt. Through March 31, 2021, approximately $666 million had been repurchased under the authorization. In March 2021, the Board authorized up to $1.8 billion to repay or repurchase additional outstanding debt, which authorization superseded any amounts that remained outstanding under any previous authorizations.
Vistra Senior Unsecured Notes
January 2020 Redemption — In January 2020, Vistra redeemed the entire $81 million aggregate principal amount outstanding of 8.000% senior notes at a redemption price equal to 104.0% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption. We recorded an extinguishment gain of $2 million on the transaction in the three months ended March 31, 2020.
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 will receive capacity payments from PJM during the Planning Years 2021-2022 in the amount of approximately $515 million. We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance with an implied interest rate of approximately 4.25%.
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). The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2020-2021 in the amount of $18 million. We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance with an implied interest rate of 0.58%.
Maturities
Long-term debt maturities at March 31, 2021 are as follows:
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
Remainder of 2021
|
$
|
354
|
|
|
2022
|
262
|
|
|
2023
|
40
|
|
|
2024
|
1,540
|
|
|
2025
|
2,470
|
|
|
Thereafter
|
5,206
|
|
|
Unamortized premiums, discounts and debt issuance costs
|
(80)
|
|
|
Total long-term debt, including amounts due currently
|
$
|
9,792
|
|
11. COMMITMENTS AND CONTINGENCIES
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
At March 31, 2021, we had outstanding letters of credit totaling $1.347 billion as follows:
•$985 million to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;
•$196 million to support battery and solar development projects;
•$34 million to support executory contracts and insurance agreements;
•$74 million to support our REP financial requirements with the PUCT, and
•$58 million for other credit support requirements.
Surety Bonds
At March 31, 2021, we had outstanding surety bonds totaling $131 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.
Gas Index Pricing Litigation — We, through our subsidiaries, and other companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. We remain as defendants in two consolidated putative class actions (Wisconsin) and one individual action (Kansas) both pending in federal court in those states. The Kansas action is currently on appeal in the U.S. Court of Appeals for the Tenth Circuit.
Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads. In March 2018, BNSF Railway Company (BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration. In March 2021, the parties entered into a confidential settlement to resolve this matter and the Coffeen matter discussed below. In connection with that settlement, BNSF and NS dismissed with prejudice their arbitration disputes for Wood River and Coffeen and these matters are fully resolved.
Coffeen and Duck Creek Rail Disputes — In April 2020, IPH, LLC (IPH) received notification that BNSF and NS were initiating dispute resolution related to IPH's suspension of its Coffeen Rail Transportation Agreement with the railroads, and Illinois Power Resources Generating, LLC (IPRG), received notification that BNSF was initiating dispute resolution related to IPRG's suspension of its Duck Creek Rail Transportation Agreement with BNSF. In November 2019, IPH and IPRG sent suspension notices to the railroads asserting that the Illinois Multi-Pollutant Standards (MPS) rule requirement to retire at least 2,000 megawatts of generation (see discussion below) was a change-in-law under the agreement that rendered continued operation of the plants no longer economically feasible. In addition, IPH and IPRG asserted that the MPS rule's retirement requirement also qualified as a force majeure event under the agreements excusing performance. In March 2021, we entered into a confidential settlement agreement with BNSF to resolve the Duck Creek matter and a separate confidential settlement agreement with BNSF and NS to resolve the Coffeen and Wood River matter discussed above. BNSF has dismissed with prejudice the Duck Creek arbitration dispute and this matter is now fully resolved. The settlement of these rail disputes did not have a material impact on our financial statements.
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 expect our opening brief will be due in June 2021. We have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with the Third Court of Appeals that the PUCT has not prejudged or made a final decision on whether to reprice and that we and other parties may continue disputing the pricing through the ERCOT process.
Koch Disputes — In March 2021, we filed a lawsuit in Texas state court against Odessa-Ector Power Partners, L.P., Koch Resources, LLC, Koch AG & Energy Solutions, LLC, and Koch Energy Services, LLC (Koch) seeking equitable relief in which we contested the amount of the February 2021 earnout payment under the terms of the 2017 asset purchase agreement (APA) with Koch pursuant to which we purchased our Odessa gas power plant for $350 million. Koch subsequently filed its own related lawsuit in Delaware Chancery Court. The APA dispute will now proceed in Delaware Chancery Court which will consider all our equitable and other claims, including our claim contesting 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. Because Koch is seeking a $286 million payment in the lawsuit, we have recorded a liability of that amount in other noncurrent liabilities and deferred credits in our condensed consolidated balance sheets. However, we will defend the case vigorously and believe that it is reasonably possible we will prevail in litigation and will not be required to pay Koch this amount.
In addition, in March 2021, we filed a lawsuit in New York state court against Koch for breach of contract and ineffective force majeure for Koch's failure to deliver gas during the event pursuant to a gas supply contract with them, as well as a claim for unjust enrichment by selling gas to others at higher prices rather than fulfilling their contract obligations to us. Koch has removed that case to New York federal court.
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 are responding to all those investigatory requests. In addition, a number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants have requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation pretrial judge, and the courts of origin have been ordered to stay further proceedings in these cases until the request for a multi-district litigation tribunal has been decided.
Climate Change
In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (the Environment Executive Order) which directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions discussed below are now subject to this review.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals to reduce nationwide CO2 emissions. Various parties filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court). In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's issuance of the rule that replaced the Clean Power Plan, the Affordable Clean Energy rule, discussed below. In September 2019, the D.C. Circuit Court granted petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.
In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. The ACE rule set a deadline of July 2022 for states to submit their plans for regulating GHG emissions from existing facilities. States where we operate coal plants (i.e., Texas, Illinois and Ohio) began to develop their state plans to comply with the rule. Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power Plan in the D.C. Circuit Court, and the D.C. Circuit Court heard argument on those issues in October 2020. In January 2021, the D.C. Circuit Court vacated the ACE rule and remanded the rule to the EPA for further action. In its decision, the D.C. Circuit Court concluded that the EPA's basis for repealing the Clean Power Plan and adopting the ACE rule was not supported by the Clean Air Act. In April 2021, the State of West Virginia and certain other parties filed a petition for review with the U.S. Supreme Court of the D.C. Circuit Court's decision. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units. Vistra submitted comments on that proposed rulemaking in March 2019. In January 2021, the EPA, just prior to the transition to the Biden administration, issued a final rule setting forth a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. The final rule excludes sectors from future regulation where GHG emissions make up less than three percent of U.S. GHG emissions. The final rule did not set any specific emission limits for new, modified, or reconstructed electric utility generating units. In April 2021, the D.C. Circuit Court granted the EPA's unopposed motion for voluntary vacatur and remand of the GHG significant contribution rule. The ACE rule and the rule on significant contribution are subject to the Environment Executive Order discussed above.
Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP). 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 our Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. The retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply with this BART rule for SO2. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas's SIP that determines that no electricity generation units are subject to BART for particulate matter. Various parties filed a petition challenging the rule in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA in the Fifth Circuit Court action. In March 2018, the Fifth Circuit Court abated its proceedings pending conclusion of the EPA's reconsideration process. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. In October 2020, environmental groups petitioned for review of this rule in both the D.C. Circuit Court and the Fifth Circuit Court. In December 2020, a panel of the Fifth Circuit Court consolidated the challenges to the BART final rule and issued an order transferring the case to the D.C. Circuit Court. As finalized, we expect that we will be able to comply with the rule. The BART rule is subject to the Environment Executive Order discussed above.
Affirmative Defenses During Malfunctions
In May 2015, the EPA finalized a rule requiring 36 states, including Texas, Illinois and Ohio, to remove or replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during upset events and unplanned maintenance and startup and shutdown events, referred to as the SIP Call. Various parties (including Luminant, the State of Texas and the State of Ohio) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. In April 2017, the D.C. Circuit Court ordered the case to be held in abeyance. In April 2019, the EPA Region 6 proposed a rule to withdraw the SIP Call with respect to the Texas affirmative defense provisions. We submitted comments on that proposed rulemaking in June 2019. In February 2020, the EPA issued the final rule withdrawing the Texas SIP Call. In April 2020, a group of environmental petitioners, including the Sierra Club, filed a petition in the D.C. Circuit Court challenging the EPA's action with respect to Texas. In October 2020, the EPA issued new guidance on the inclusion of startup, shutdown and malfunction (SSM) provisions in SIPs, which is intended to supersede the policy in the multi-state SIP Call. The guidance provides that the SIPs may contain provisions for SSM events if certain conditions are met. The EPA SSM guidance is subject to the Environment Executive Order discussed above.
Illinois Multi-Pollutant Standards (MPS)
In August 2019, changes proposed by the Illinois Pollution Control Board to the MPS rule, which places NOX, SO2 and mercury emissions limits on our coal plants located in MISO went into effect. Under the revised MPS rule, our allowable SO2 and NOX emissions from the MISO fleet are 48% and 42% lower, respectively, than prior to the rule changes. The revised MPS rule requires the continuous operation of existing selective catalytic reduction (SCR) control systems during the ozone season, requires SCR-controlled units to meet an ozone season NOX emission rate limit, and set an additional, site-specific annual SO2 limit for our Joppa Power Station. Additionally, in 2019, the Company retired its Havana, Hennepin, Coffeen and Duck Creek plants in order to comply with the MPS rule's requirement to retire at least 2,000 MW of our generation in MISO.
SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation 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. Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would revise its previous nonattainment designations and each area at issue would be designated unclassifiable. In September 2019, we submitted comments in support of the proposed Error Correction Rule. In April 2020, the Sierra Club filed suit to compel the EPA to issue a Finding of Failure to submit an attainment plan with respect to the three areas in Texas. In August 2020, the EPA issued a Finding of Failure for Texas to submit an attainment plan. In September 2020, the EPA proposed a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, which, if finalized, would redesignate those areas as attainment based on monitoring data supporting an attainment designation. We expect the TCEQ to develop a SIP for Texas for submittal to the EPA in 2021.
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 August 2017, the EPA announced that its reconsideration of the ELG rule would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rule for the application of effluent limitations for FGD and bottom ash wastewaters from November 1, 2018 to November 1, 2020. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to effluent limitations. The remainder of the case proceeded, and in April 2019 the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. In November 2019, the EPA issued a proposal that would extend the compliance deadline for FGD wastewater to no later than December 31, 2025 and maintains the December 31, 2023 compliance date for bottom ash transport water. The proposal also creates new sub-categories of facilities with more flexible FGD compliance options, including a retirement exemption to 2028 and a low utilization boiler exemption. The proposed rule also modified some of the FGD final effluent limitations. We filed comments on the proposal in January 2020. The EPA published the final rule in October 2020. The final rule extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. Notification to the state agency on the retirement exemption is due by October 2021. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. The final rule is subject to the Environment Executive Order discussed above.
Coal Combustion Residuals (CCR)/Groundwater
In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of the CCR rule that the agency issued in 2015. Among other changes, the 2018 revisions extended closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. Also, in August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In December 2019, the EPA issued a proposed rule containing a revised closure deadline for unlined CCR impoundments and new procedures for seeking extensions of that revised closure deadline. We filed comments on the proposal in January 2020. In August 2020, the EPA issued a rule finalizing the December 2019 proposal, establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. 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 October 2020, the EPA published an advanced notice of proposed rulemaking requesting information to inform the EPA in the development of a rule to address legacy impoundments that existed prior to the 2015 CCR regulation as required by the August 2018 D.C. Circuit Court decision. We filed comments on this proposal in February 2021. The rules on revised closure deadlines and alternative liner demonstrations are subject to the Environment Executive Order discussed above.
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 are working towards implementation of those closure plans.
At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the aforementioned D.C. 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 filed a citizen suit in federal court in Illinois against DMG, alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. Plaintiffs have appealed the judgment to the U.S. Court of Appeals for the Seventh Circuit and argument was heard in November 2020. In April 2019, PRN also filed a complaint against DMG before the IPCB, alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992. This matter is in the very early stages.
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility and that notice has since been referred to the Illinois Attorney General.
In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the Coffeen, Edwards and Joppa generation facilities are causing exceedances of the applicable groundwater standards. In April 2021, we entered into a settlement agreement with the Sierra Club to resolve this matter. As part of that agreement, we agreed to accelerate the timeline for the closure of the Joppa Power Plant and will now close the plant by September 1, 2022. This matter is now fully resolved.
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. In March 2020, the IEPA issued its proposed rule. Under the proposed rule, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The proposed rule does not mandate closure by removal at any site. Public hearings for the proposed rule were held in August 2020 and September 2020. The rule was finalized and became effective in April 2021.
For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule will require us to undertake further site specific evaluations which are underway. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been submitted and approved by the IEPA. However, the currently anticipated CCR surface impoundment and landfill closure costs, as contained in our AROs, reflect the costs of closure methods that meet the requirements and that our operations and environmental services teams believe are appropriate and protective of the environment for each location.
MISO 2015-2016 Planning Resource Auction
In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO. 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 FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint.
In October 2015, FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA.
In December 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order.
In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. With the issuance of the order, this matter has been resolved in Dynegy's favor. The request for rehearing was denied by FERC in March 2020. 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. The appeal remains pending.
Other Matters
We are involved in various legal and administrative proceedings and other disputes in the normal course of business, including disputes over certain gas invoices, 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.
12. EQUITY
Share Repurchase Programs
In September 2020, we announced that the Board authorized a new share repurchase program (Share Repurchase Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on January 1, 2021.
Under the Share Repurchase Program, shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements.
In the three months ended March 31, 2021, 8,658,153 shares of our common stock were repurchased under the Share Repurchase Program for approximately $175 million (including related fees and expenses) at an average price of $20.21 per share of common stock. As of March 31, 2021, approximately $1.325 billion was available for additional repurchases under the Share Repurchase Program.
Dividends
In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations.
In February 2020, April 2020, July 2020 and October 2020, the Board declared quarterly dividends of $0.135 per share that were paid in March 2020, June 2020, September 2020 and December 2020, respectively.
In February 2021, the Board declared a quarterly dividend of $0.15 per share that was paid in March 2021. In April 2021, the Board declared a quarterly dividend of $0.15 per share that will be paid in June 2021.
Dividend Restrictions
The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of March 31, 2021, Vistra Operations can distribute approximately $5.5 billion to Parent under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $230 million and $110 million during the three months ended March 31, 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 March 31, 2021, all of the restricted net assets of Vistra Operations may be distributed to Parent.
In addition to the restrictions under the Credit Facilities Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year.
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. As of March 31, 2021, nine million warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Merger Date.
Equity
The following table presents the changes to equity for the three months ended March 31, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock (a)
|
|
Treasury Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings (Deficit)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total Stockholders' Equity
|
|
Noncontrolling Interest in Subsidiary
|
|
Total Equity
|
|
Balance at
December 31, 2020
|
$
|
5
|
|
|
$
|
(973)
|
|
|
$
|
9,786
|
|
|
$
|
(399)
|
|
|
$
|
(48)
|
|
|
$
|
8,371
|
|
|
$
|
(10)
|
|
|
$
|
8,361
|
|
|
Stock repurchase
|
—
|
|
|
(175)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(175)
|
|
|
—
|
|
|
(175)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(74)
|
|
|
—
|
|
|
(74)
|
|
|
—
|
|
|
(74)
|
|
|
Effects of stock-based incentive compensation plans
|
—
|
|
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,043)
|
|
|
—
|
|
|
(2,043)
|
|
|
3
|
|
|
(2,040)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in accumulated other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
Balance at March 31, 2021
|
$
|
5
|
|
|
$
|
(1,148)
|
|
|
$
|
9,805
|
|
|
$
|
(2,516)
|
|
|
$
|
(46)
|
|
|
$
|
6,100
|
|
|
$
|
(7)
|
|
|
$
|
6,093
|
|
________________
(a)Authorized shares totaled 1,800,000,000 at March 31, 2021. Outstanding common shares totaled 481,468,094 and 489,305,888 at March 31, 2021 and December 31, 2020, respectively. Treasury shares totaled 49,701,377 and 41,043,224 at March 31, 2021 and December 31, 2020, respectively.
The following table presents the changes to equity for the three months ended March 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock (a)
|
|
Treasury Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings (Deficit)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total Stockholders' Equity
|
|
Noncontrolling Interest in Subsidiary
|
|
Total Equity
|
|
Balance at
December 31, 2019
|
$
|
5
|
|
|
$
|
(973)
|
|
|
$
|
9,721
|
|
|
$
|
(764)
|
|
|
$
|
(30)
|
|
|
$
|
7,959
|
|
|
$
|
1
|
|
|
$
|
7,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(66)
|
|
|
—
|
|
|
(66)
|
|
|
—
|
|
|
(66)
|
|
|
Effects of stock-based incentive compensation plans
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
14
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
|
—
|
|
|
56
|
|
|
(11)
|
|
|
45
|
|
|
Adoption of accounting standard
|
—
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
(4)
|
|
|
Change in accumulated other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23)
|
|
|
(23)
|
|
|
—
|
|
|
(23)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
—
|
|
|
—
|
|
|
2
|
|
|
(2)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Balance at March 31, 2020
|
$
|
5
|
|
|
$
|
(973)
|
|
|
$
|
9,737
|
|
|
$
|
(780)
|
|
|
$
|
(53)
|
|
|
$
|
7,936
|
|
|
$
|
(10)
|
|
|
$
|
7,926
|
|
________________
(a)Authorized shares totaled 1,800,000,000 at March 31, 2020. Outstanding common shares totaled 488,448,029 and 487,698,111 at March 31, 2020 and December 31, 2019, respectively. Treasury shares totaled 41,043,224 at both March 31, 2020 and December 31, 2019.
13. 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 14 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
Level
1
|
|
Level
2
|
|
Level
3 (a)
|
|
Reclass
(b)
|
|
Total
|
|
Level
1
|
|
Level
2
|
|
Level
3 (a)
|
|
Reclass
(b)
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
399
|
|
|
$
|
173
|
|
|
$
|
379
|
|
|
$
|
64
|
|
|
$
|
1,015
|
|
|
$
|
452
|
|
|
$
|
201
|
|
|
$
|
205
|
|
|
$
|
76
|
|
|
$
|
934
|
|
|
Interest rate swaps
|
—
|
|
|
42
|
|
|
—
|
|
|
—
|
|
|
42
|
|
|
—
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|
Nuclear decommissioning trust – equity securities (c)
|
662
|
|
|
—
|
|
|
—
|
|
|
|
|
662
|
|
|
623
|
|
|
—
|
|
|
—
|
|
|
|
|
623
|
|
|
Nuclear decommissioning trust – debt securities (c)
|
—
|
|
|
596
|
|
|
—
|
|
|
|
|
596
|
|
|
—
|
|
|
618
|
|
|
—
|
|
|
|
|
618
|
|
|
Sub-total
|
$
|
1,061
|
|
|
$
|
811
|
|
|
$
|
379
|
|
|
$
|
64
|
|
|
2,315
|
|
|
$
|
1,075
|
|
|
$
|
891
|
|
|
$
|
205
|
|
|
$
|
76
|
|
|
2,247
|
|
|
Assets measured at net asset value (d):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trust – equity securities (c)
|
|
|
|
|
|
|
|
|
460
|
|
|
|
|
|
|
|
|
|
|
433
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
$
|
2,775
|
|
|
|
|
|
|
|
|
|
|
$
|
2,680
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
572
|
|
|
$
|
212
|
|
|
$
|
175
|
|
|
$
|
64
|
|
|
$
|
1,023
|
|
|
$
|
578
|
|
|
$
|
172
|
|
|
$
|
183
|
|
|
$
|
76
|
|
|
$
|
1,009
|
|
|
Interest rate swaps
|
—
|
|
|
286
|
|
|
—
|
|
|
—
|
|
|
286
|
|
|
—
|
|
|
404
|
|
|
—
|
|
|
—
|
|
|
404
|
|
|
Total liabilities
|
$
|
572
|
|
|
$
|
498
|
|
|
$
|
175
|
|
|
$
|
64
|
|
|
$
|
1,309
|
|
|
$
|
578
|
|
|
$
|
576
|
|
|
$
|
183
|
|
|
$
|
76
|
|
|
$
|
1,413
|
|
___________
(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 condensed consolidated balance sheets.
(c)The nuclear decommissioning trust investment is included in the other investments line in our condensed consolidated balance sheets. See Note 17.
(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 condensed consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.
Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 14 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 March 31, 2021 and December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
|
Average (b)
|
|
Electricity purchases and sales
|
|
$
|
234
|
|
|
$
|
(43)
|
|
|
$
|
191
|
|
|
Income Approach
|
|
Hourly price curve shape (c)
|
|
$
|
—
|
|
to
|
$75
|
|
$37
|
|
|
|
|
|
|
|
|
|
|
MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for hub power prices and heat rates (d)
|
|
$
|
10
|
|
to
|
$130
|
|
$69
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh
|
|
|
|
Options
|
|
41
|
|
|
(102)
|
|
|
(61)
|
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
20
|
%
|
to
|
100%
|
|
57%
|
|
|
|
|
|
|
|
|
|
Power and gas volatility (e)
|
|
5
|
%
|
to
|
670%
|
|
336%
|
|
Financial transmission rights
|
|
86
|
|
|
(17)
|
|
|
69
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$
|
(30)
|
|
to
|
$55
|
|
$12
|
|
|
|
|
|
|
|
|
|
|
MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (h)
|
|
18
|
|
|
(13)
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
379
|
|
|
$
|
(175)
|
|
|
$
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
|
Average (b)
|
|
Electricity purchases and sales
|
|
$
|
61
|
|
|
$
|
(90)
|
|
|
$
|
(29)
|
|
|
Income Approach
|
|
Hourly price curve shape (c)
|
|
$
|
—
|
|
to
|
$85
|
|
$43
|
|
|
|
|
|
|
|
|
|
|
MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
|
|
$
|
25
|
|
to
|
$125
|
|
$75
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh
|
|
|
|
Options
|
|
38
|
|
|
(56)
|
|
|
(18)
|
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
30
|
%
|
to
|
100%
|
|
64%
|
|
|
|
|
|
|
|
|
|
Power and gas volatility (e)
|
|
5
|
%
|
to
|
665%
|
|
336%
|
|
Financial transmission rights
|
|
92
|
|
|
(16)
|
|
|
76
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$
|
(5)
|
|
to
|
$50
|
|
$22
|
|
|
|
|
|
|
|
|
|
|
MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (h)
|
|
14
|
|
|
(21)
|
|
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
205
|
|
|
$
|
(183)
|
|
|
$
|
22
|
|
|
|
|
|
|
|
|
|
|
|
____________
(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)Other includes contracts for natural gas, coal and environmental allowances.
See the table below for discussion of transfers between Level 2 and Level 3 for the three months ended March 31, 2021 and 2020.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the three months ended March 31, 2021 and 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Net asset (liability) balance at beginning of period
|
|
|
|
|
$
|
22
|
|
|
$
|
(74)
|
|
|
Total unrealized valuation gains (losses)
|
|
|
|
|
190
|
|
|
(6)
|
|
|
Purchases, issuances and settlements (a):
|
|
|
|
|
|
|
|
|
Purchases
|
|
|
|
|
17
|
|
|
55
|
|
|
Issuances
|
|
|
|
|
(6)
|
|
|
(3)
|
|
|
Settlements
|
|
|
|
|
(19)
|
|
|
(13)
|
|
|
Transfers into Level 3 (b)
|
|
|
|
|
1
|
|
|
1
|
|
|
Transfers out of Level 3 (b)
|
|
|
|
|
(1)
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change (c)
|
|
|
|
|
182
|
|
|
102
|
|
|
Net asset balance at end of period
|
|
|
|
|
$
|
204
|
|
|
$
|
28
|
|
|
Unrealized valuation gains relating to instruments held at end of period
|
|
|
|
|
$
|
194
|
|
|
$
|
23
|
|
____________
(a)Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.
(b)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the three months ended March 31, 2020, transfers out of Level 3 primarily consist of gas and coal derivatives where forward pricing inputs have become observable.
(c)Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our condensed consolidated statements of operations.
14.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 13 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 condensed 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 condensed 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 condensed consolidated balance sheets at March 31, 2021 and December 31, 2020. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Total
|
|
Current assets
|
$
|
655
|
|
|
$
|
19
|
|
|
$
|
36
|
|
|
$
|
—
|
|
|
$
|
710
|
|
|
Noncurrent assets
|
308
|
|
|
23
|
|
|
16
|
|
|
—
|
|
|
347
|
|
|
Current liabilities
|
(4)
|
|
|
—
|
|
|
(793)
|
|
|
(71)
|
|
|
(868)
|
|
|
Noncurrent liabilities
|
(8)
|
|
|
—
|
|
|
(218)
|
|
|
(215)
|
|
|
(441)
|
|
|
Net assets (liabilities)
|
$
|
951
|
|
|
$
|
42
|
|
|
$
|
(959)
|
|
|
$
|
(286)
|
|
|
$
|
(252)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Total
|
|
Current assets
|
$
|
665
|
|
|
$
|
19
|
|
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
748
|
|
|
Noncurrent assets
|
197
|
|
|
53
|
|
|
8
|
|
|
—
|
|
|
258
|
|
|
Current liabilities
|
(1)
|
|
|
—
|
|
|
(717)
|
|
|
(71)
|
|
|
(789)
|
|
|
Noncurrent liabilities
|
(3)
|
|
|
—
|
|
|
(288)
|
|
|
(333)
|
|
|
(624)
|
|
|
Net assets (liabilities)
|
$
|
858
|
|
|
$
|
72
|
|
|
$
|
(933)
|
|
|
$
|
(404)
|
|
|
$
|
(407)
|
|
At March 31, 2021 and December 31, 2020, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative (condensed consolidated statements of operations presentation)
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2021
|
|
2020
|
|
Commodity contracts (Operating revenues)
|
|
|
|
|
$
|
86
|
|
|
$
|
257
|
|
|
Commodity contracts (Fuel, purchased power costs and delivery fees)
|
|
|
|
|
40
|
|
|
(106)
|
|
|
Interest rate swaps (Interest expense and related charges)
|
|
|
|
|
75
|
|
|
(178)
|
|
|
Net gain (loss)
|
|
|
|
|
$
|
201
|
|
|
$
|
(27)
|
|
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our condensed 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 condensed 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
|
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
|
|
$
|
951
|
|
|
$
|
(629)
|
|
|
$
|
(32)
|
|
|
$
|
290
|
|
|
$
|
858
|
|
|
$
|
(667)
|
|
|
$
|
(11)
|
|
|
$
|
180
|
|
|
Interest rate swaps
|
|
42
|
|
|
(42)
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|
(72)
|
|
|
—
|
|
|
—
|
|
|
Total derivative assets
|
|
993
|
|
|
(671)
|
|
|
(32)
|
|
|
290
|
|
|
930
|
|
|
(739)
|
|
|
(11)
|
|
|
180
|
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
(959)
|
|
|
629
|
|
|
185
|
|
|
(145)
|
|
|
(933)
|
|
|
667
|
|
|
138
|
|
|
(128)
|
|
|
Interest rate swaps
|
|
(286)
|
|
|
42
|
|
|
—
|
|
|
(244)
|
|
|
(404)
|
|
|
72
|
|
|
—
|
|
|
(332)
|
|
|
Total derivative liabilities
|
|
(1,245)
|
|
|
671
|
|
|
185
|
|
|
(389)
|
|
|
(1,337)
|
|
|
739
|
|
|
138
|
|
|
(460)
|
|
|
Net amounts
|
|
$
|
(252)
|
|
|
$
|
—
|
|
|
$
|
153
|
|
|
$
|
(99)
|
|
|
$
|
(407)
|
|
|
$
|
—
|
|
|
$
|
127
|
|
|
$
|
(280)
|
|
____________
(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 March 31, 2021 and December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
|
Derivative type
|
|
Notional Volume
|
|
Unit of Measure
|
|
Natural gas (a)
|
|
5,198
|
|
|
5,264
|
|
|
Million MMBtu
|
|
Electricity
|
|
420,600
|
|
|
438,863
|
|
|
GWh
|
|
Financial transmission rights (b)
|
|
192,197
|
|
|
217,350
|
|
|
GWh
|
|
Coal
|
|
13
|
|
|
20
|
|
|
Million U.S. tons
|
|
Fuel oil
|
|
140
|
|
|
176
|
|
|
Million gallons
|
|
|
|
|
|
|
|
|
|
Emissions
|
|
11
|
|
|
8
|
|
|
Million tons
|
|
Renewable energy certificates
|
|
22
|
|
|
18
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Fair value of derivative contract liabilities (a)
|
$
|
(549)
|
|
|
$
|
(679)
|
|
|
Offsetting fair value under netting arrangements (b)
|
215
|
|
|
262
|
|
|
Cash collateral and letters of credit
|
41
|
|
|
35
|
|
|
Liquidity exposure
|
$
|
(293)
|
|
|
$
|
(382)
|
|
____________
(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. At March 31, 2021, total credit risk exposure to all counterparties related to derivative contracts totaled $1.128 billion (including associated accounts receivable). The net exposure to those counterparties totaled $352 million at March 31, 2021, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $69 million. At March 31, 2021, the credit risk exposure to the banking and financial sector represented 67% of the total credit risk exposure and 45% 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.
15.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 Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra common stock held by such selling stockholders.
In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra common stock held by certain significant stockholders pursuant to the Registration Rights Agreement, which was declared effective by the SEC in May 2017. The registration statement was amended in March 2018. Pursuant to the Registration Rights Agreement, in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on Form S-3, which was declared effective by the SEC in July 2018. Among other things, under the terms of the Registration Rights Agreement:
•if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and
•the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration (as defined in the Registration Rights Agreement) and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed.
All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us.
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.
16.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. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. Management believes the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The following is a summary of the updated segments:
•The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments As we announced significant plant closures in the third quarter of 2020, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.
•The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes operations in PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.
•The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporate and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 2), the Company expects to expand its operations in the West segment.
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 the ERCOT market and was referred to as the ERCOT segment prior to the third quarter of 2020. The East segment represents results from the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics.
The West segment represents results from the CAISO market, including our development of battery ESS projects at our Moss Landing and Oakland power plant sites (see Note 2).
The Sunset segment consists of generation plants with announced retirement plans. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement plans.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. We have not allocated any unrealized gains or losses on the commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018, 2019 and 2020.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating segments.
The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on U.S. 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.
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|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended
|
|
Retail
|
|
Texas
|
|
East
|
|
West
|
|
Sunset
|
|
Asset Closure
|
|
Corporate and Other (b)
|
|
Eliminations
|
|
Consolidated
|
|
Operating revenues (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
$
|
1,750
|
|
|
$
|
1,083
|
|
|
$
|
724
|
|
|
$
|
33
|
|
|
$
|
279
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(662)
|
|
|
$
|
3,207
|
|
|
March 31, 2020
|
|
1,908
|
|
|
861
|
|
|
734
|
|
|
82
|
|
|
346
|
|
|
—
|
|
|
—
|
|
|
(1,073)
|
|
|
2,858
|
|
|
Depreciation and amortization:
|
|
March 31, 2021
|
|
$
|
(53)
|
|
|
$
|
(124)
|
|
|
$
|
(196)
|
|
|
$
|
(5)
|
|
|
$
|
(29)
|
|
|
$
|
—
|
|
|
$
|
(16)
|
|
|
$
|
—
|
|
|
$
|
(423)
|
|
|
March 31, 2020
|
|
(80)
|
|
|
(113)
|
|
|
(168)
|
|
|
(5)
|
|
|
(39)
|
|
|
—
|
|
|
(14)
|
|
|
—
|
|
|
(419)
|
|
|
Operating income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
$
|
94
|
|
|
$
|
(2,556)
|
|
|
$
|
2
|
|
|
$
|
(35)
|
|
|
$
|
(44)
|
|
|
$
|
(16)
|
|
|
$
|
(28)
|
|
|
$
|
—
|
|
|
$
|
(2,583)
|
|
|
March 31, 2020
|
|
99
|
|
|
272
|
|
|
92
|
|
|
3
|
|
|
(27)
|
|
|
(17)
|
|
|
(31)
|
|
|
—
|
|
|
391
|
|
|
Net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
$
|
88
|
|
|
$
|
(2,518)
|
|
|
$
|
1
|
|
|
$
|
(31)
|
|
|
$
|
(43)
|
|
|
$
|
—
|
|
|
$
|
463
|
|
|
$
|
—
|
|
|
$
|
(2,040)
|
|
|
March 31, 2020
|
|
95
|
|
|
273
|
|
|
65
|
|
|
4
|
|
|
(25)
|
|
|
(18)
|
|
|
(349)
|
|
|
—
|
|
|
45
|
|
|
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
|
|
March 31, 2021
|
|
$
|
—
|
|
|
$
|
46
|
|
|
$
|
6
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
(2)
|
|
|
$
|
—
|
|
|
$
|
55
|
|
|
March 31, 2020
|
|
—
|
|
|
69
|
|
|
18
|
|
|
1
|
|
|
12
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
122
|
|
___________
(a)The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended
|
|
Retail
|
|
Texas
|
|
East
|
|
West
|
|
Sunset
|
|
Asset Closure
|
|
Corporate and Other
|
|
Eliminations (1)
|
|
Consolidated
|
|
March 31, 2021
|
|
$
|
(4)
|
|
|
$
|
(541)
|
|
|
$
|
(35)
|
|
|
$
|
(53)
|
|
|
$
|
(99)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
790
|
|
|
$
|
58
|
|
|
March 31, 2020
|
|
1
|
|
|
203
|
|
|
54
|
|
|
7
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
(119)
|
|
|
$
|
201
|
|
____________
(1)Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(b)Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate and Other net income.
17.SUPPLEMENTARY FINANCIAL INFORMATION
Impairment of Long-Lived Assets
In the first quarter of 2020, we recognized an impairment loss of $52 million related to our Joppa/EEI coal generation facility in Illinois as a result of a significant decrease in the estimated useful life of the facility, reflecting a decrease in the economic forecast of the facility and changes to the operating assumption based on lower forecasted wholesale electricity prices. We also recorded a $32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facility and therefore determined to have a significant decrease in estimated useful life. The impairments are reported in our Sunset segment and include a $45 million write-down of property, plant and equipment, a $32 million write-down of intangible assets and a $7 million write-down of inventory.
Interest Expense and Related Charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Interest paid/accrued
|
|
|
|
|
$
|
112
|
|
|
$
|
128
|
|
|
Unrealized mark-to-market net (gains) losses on interest rate swaps
|
|
|
|
|
(88)
|
|
|
174
|
|
|
Amortization of debt issuance costs, discounts and premiums
|
|
|
|
|
5
|
|
|
4
|
|
|
Debt extinguishment gain
|
|
|
|
|
—
|
|
|
(8)
|
|
|
Capitalized interest
|
|
|
|
|
(8)
|
|
|
(3)
|
|
|
Other
|
|
|
|
|
8
|
|
|
5
|
|
|
Total interest expense and related charges
|
|
|
|
|
$
|
29
|
|
|
$
|
300
|
|
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 3.88% and 3.67% at March 31, 2021 and 2020.
Other Income and Deductions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Insurance settlement (a)
|
|
|
|
|
$
|
38
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
Gain on settlement of rail transportation disputes (b)
|
|
|
|
|
15
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
|
|
—
|
|
|
1
|
|
|
All other
|
|
|
|
|
2
|
|
|
3
|
|
|
Total other income
|
|
|
|
|
$
|
55
|
|
|
$
|
7
|
|
|
Other deductions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on disposal of investment in NELP (c)
|
|
|
|
|
$
|
—
|
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All other
|
|
|
|
|
5
|
|
|
3
|
|
|
Total other deductions
|
|
|
|
|
$
|
5
|
|
|
$
|
31
|
|
____________
(a)For the three months ended March 31, 2021, $36 million reported in the Texas segment and $2 million reported in the Corporate and other non-segment. The amount for the three months ended March 31, 2020 reported in the Corporate and Other non-segment.
(b)Reported in the Asset Closure segment.
(c)Reported in the East segment.
Restricted Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
Current Assets
|
|
Noncurrent Assets
|
|
Current Assets
|
|
Noncurrent Assets
|
|
|
|
|
|
|
|
|
|
|
Amounts related to remediation escrow accounts
|
$
|
22
|
|
|
$
|
18
|
|
|
$
|
19
|
|
|
$
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total restricted cash
|
$
|
22
|
|
|
$
|
18
|
|
|
$
|
19
|
|
|
$
|
19
|
|
Trade Accounts Receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Wholesale and retail trade accounts receivable
|
$
|
1,359
|
|
|
$
|
1,324
|
|
|
Allowance for uncollectible accounts
|
(43)
|
|
|
(45)
|
|
|
Trade accounts receivable — net
|
$
|
1,316
|
|
|
$
|
1,279
|
|
Gross trade accounts receivable at March 31, 2021 and December 31, 2020 included unbilled retail revenues of $472 million and $468 million, respectively.
Allowance for Uncollectible Accounts Receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2021
|
|
2020
|
|
Allowance for uncollectible accounts receivable at beginning of period
|
$
|
45
|
|
|
$
|
42
|
|
|
Increase for bad debt expense
|
28
|
|
|
26
|
|
|
Decrease for account write-offs
|
(30)
|
|
|
(28)
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts receivable at end of period
|
$
|
43
|
|
|
$
|
40
|
|
Inventories by Major Category
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Materials and supplies
|
$
|
261
|
|
|
$
|
260
|
|
|
Fuel stock
|
189
|
|
|
236
|
|
|
Natural gas in storage
|
17
|
|
|
19
|
|
|
Total inventories
|
$
|
467
|
|
|
$
|
515
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Nuclear plant decommissioning trust
|
$
|
1,718
|
|
|
$
|
1,674
|
|
|
Assets related to employee benefit plans
|
41
|
|
|
41
|
|
|
Land
|
44
|
|
|
44
|
|
|
|
|
|
|
|
Total investments
|
$
|
1,803
|
|
|
$
|
1,759
|
|
Investment in Unconsolidated Subsidiary
Prior to March 2020, we owned a 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 $28 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 condensed consolidated statements of operations in other deductions.
Equity earnings related to our investment in NELP totaled $3 million for the three months ended March 31, 2020, recorded in equity in earnings (loss) of unconsolidated investment in our condensed consolidated statements of operations. We received distributions totaling $3 million for the three months ended March 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 Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31, 2020
|
|
Debt securities (a)
|
$
|
596
|
|
|
$
|
618
|
|
|
Equity securities (b)
|
1,122
|
|
|
1,056
|
|
|
Total
|
$
|
1,718
|
|
|
$
|
1,674
|
|
____________
(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 2.77% and 2.91% at March 31, 2021 and December 31, 2020, respectively, and an average maturity of ten years at both March 31, 2021 and December 31, 2020.
(b)The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments.
Debt securities held at March 31, 2021 mature as follows: $199 million in one to five years, $196 million in five to 10 years and $201 million after 10 years.
The following table summarizes proceeds from sales of securities and investments in new securities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Proceeds from sales of securities
|
|
|
|
|
$
|
133
|
|
|
$
|
75
|
|
|
Investments in securities
|
|
|
|
|
$
|
(138)
|
|
|
$
|
(80)
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Power generation and structures
|
$
|
15,283
|
|
|
$
|
15,222
|
|
|
Land
|
616
|
|
|
617
|
|
|
Office and other equipment
|
176
|
|
|
173
|
|
|
Total
|
16,075
|
|
|
16,012
|
|
|
Less accumulated depreciation
|
(3,925)
|
|
|
(3,614)
|
|
|
Net of accumulated depreciation
|
12,150
|
|
|
12,398
|
|
|
Finance lease right-of-use assets (net of accumulated depreciation)
|
179
|
|
|
182
|
|
|
Nuclear fuel (net of accumulated amortization of $112 million and $91 million)
|
193
|
|
|
207
|
|
|
Construction work in progress
|
870
|
|
|
712
|
|
|
Property, plant and equipment — net
|
$
|
13,392
|
|
|
$
|
13,499
|
|
Depreciation expenses totaled $355 million and $328 million for three months ended March 31, 2021 and 2020, respectively.
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. We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets. However, because the period of remediation is indeterminable, no removal liabilities have been recognized.
At March 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.597 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our condensed consolidated balance sheet of $121 million in other noncurrent liabilities and deferred credits.
The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the three months ended March 31, 2021 and 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2021
|
|
Three Months Ended March 31, 2020
|
|
|
Nuclear Plant Decom-
missioning
|
|
Mining Land Reclamation
|
|
Coal Ash and Other
|
|
Total
|
|
Nuclear Plant Decom-
missioning
|
|
Mining Land Reclamation
|
|
Coal Ash and Other
|
|
Total
|
|
Liability at beginning of period
|
$
|
1,585
|
|
|
$
|
359
|
|
|
$
|
492
|
|
|
$
|
2,436
|
|
|
$
|
1,320
|
|
|
$
|
410
|
|
|
$
|
508
|
|
|
$
|
2,238
|
|
|
Additions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
|
12
|
|
|
5
|
|
|
6
|
|
|
23
|
|
|
11
|
|
|
5
|
|
|
7
|
|
|
23
|
|
|
Adjustment for change in estimates
|
—
|
|
|
—
|
|
|
(5)
|
|
|
(5)
|
|
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reductions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments
|
—
|
|
|
(15)
|
|
|
(3)
|
|
|
(18)
|
|
|
—
|
|
|
(13)
|
|
|
(7)
|
|
|
(20)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability at end of period
|
1,597
|
|
|
349
|
|
|
490
|
|
|
2,436
|
|
|
1,331
|
|
|
401
|
|
|
508
|
|
|
2,240
|
|
|
Less amounts due currently
|
—
|
|
|
(82)
|
|
|
(17)
|
|
|
(99)
|
|
|
—
|
|
|
(97)
|
|
|
(54)
|
|
|
(151)
|
|
|
Noncurrent liability at end of period
|
$
|
1,597
|
|
|
$
|
267
|
|
|
$
|
473
|
|
|
$
|
2,337
|
|
|
1,331
|
|
|
304
|
|
|
454
|
|
|
2,089
|
|
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Retirement and other employee benefits
|
$
|
312
|
|
|
$
|
312
|
|
|
Winter Storm Uri impact (a)
|
722
|
|
|
—
|
|
|
Identifiable intangible liabilities (Note 5)
|
230
|
|
|
289
|
|
|
Regulatory liability
|
121
|
|
|
89
|
|
|
Finance lease liabilities
|
218
|
|
|
206
|
|
|
Uncertain tax positions, including accrued interest
|
13
|
|
|
12
|
|
|
Liability for third-party remediation
|
33
|
|
|
31
|
|
|
|
|
|
|
|
Accrued severance costs
|
55
|
|
|
54
|
|
|
Other accrued expenses
|
144
|
|
|
138
|
|
|
Total other noncurrent liabilities and deferred credits
|
$
|
1,848
|
|
|
$
|
1,131
|
|
____________
(a)Includes the allocation of ERCOT default uplift charges, accrual of Koch earn-out disputed amounts (see Note 11) and future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.
Fair Value of Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
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
|
|
$
|
2,571
|
|
|
$
|
2,545
|
|
|
$
|
2,579
|
|
|
$
|
2,565
|
|
|
Vistra Operations Senior Notes
|
|
Level 2
|
|
6,636
|
|
|
6,962
|
|
|
6,634
|
|
|
7,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward Capacity Agreements
|
|
Level 3
|
|
519
|
|
|
519
|
|
|
45
|
|
|
45
|
|
|
Equipment Financing Agreements
|
|
Level 3
|
|
56
|
|
|
56
|
|
|
59
|
|
|
59
|
|
|
Building Financing
|
|
Level 2
|
|
7
|
|
|
7
|
|
|
10
|
|
|
10
|
|
|
Other debt
|
|
Level 3
|
|
3
|
|
|
3
|
|
|
3
|
|
|
3
|
|
We determine fair value in accordance with accounting standards as discussed in Note 13. 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 condensed consolidated statements of cash flows to the amounts reported in our condensed consolidated balance sheets at March 31, 2021 and December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
Cash and cash equivalents
|
$
|
561
|
|
|
$
|
406
|
|
|
Restricted cash included in current assets
|
22
|
|
|
19
|
|
|
Restricted cash included in noncurrent assets
|
18
|
|
|
19
|
|
|
Total cash, cash equivalents and restricted cash
|
$
|
601
|
|
|
$
|
444
|
|
The following table summarizes our supplemental cash flow information for the three months ended March 31, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2021
|
|
2020
|
|
Cash payments related to:
|
|
|
|
|
Interest paid
|
$
|
191
|
|
|
$
|
208
|
|
|
Capitalized interest
|
(8)
|
|
|
(3)
|
|
|
Interest paid (net of capitalized interest)
|
$
|
183
|
|
|
$
|
205
|
|
|
Income taxes paid (refunds received) (a)
|
$
|
7
|
|
|
$
|
(36)
|
|
|
|
|
|
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
Disposition of investment in NELP
|
$
|
—
|
|
|
$
|
123
|
|
|
Acquisition of investment in NJEA
|
$
|
—
|
|
|
$
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________
(a)For the three months ended March 31, 2021 and 2020, we paid state income taxes of $8 million and $1 million, respectively, received federal tax refunds of zero and $37 million, respectively, and received state tax refunds of $1 million and zero, respectively.