Filed: 26 Feb 21, 7:45am
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|☒||ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020
— OR —
|☐||TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the transition period from __ to __
Commission File Number 001-38086
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of incorporation or organization)||(I.R.S. Employer Identification No.)|
|6555 Sierra Drive||Irving,||Texas||75039||(214)||812-4600|
|(Address of principal executive offices) (Zip Code)||(Registrant's telephone number, including area code)|
Securities registered pursuant to Section 12(b) of the Act:
|Title of Each Class||Trading Symbol(s)||Name of Each Exchange on Which Registered|
|Common stock, par value $0.01 per share||VST||New York Stock Exchange|
|Warrants||VST.WS.A||New York Stock Exchange|
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicated by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
|Large accelerated filer||☒||Accelerated filer||☐||Non-accelerated filer||☐||Smaller reporting company||☐||Emerging growth company||☐|
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
As of June 30, 2020, the aggregate market value of the Vistra Corp. common stock held by non-affiliates of the registrant was $9,084,469,142 based on the closing sale price as reported on the New York Stock Exchange.
As of February 23, 2021, there were 483,716,012 shares of common stock, par value $0.01, outstanding of Vistra Corp.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the registrant's 2021 annual meeting of stockholders are incorporated in Part III of this annual report on Form 10-K.
TABLE OF CONTENTS
Vistra Corp.'s (Vistra) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public, free of charge, on the Vistra website at http://www.vistracorp.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. Additionally, Vistra posts important information, including press releases, investor presentations, sustainability reports, and notices of upcoming events on its website and utilizes its website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of posting to the website by signing up for email alerts and RSS feeds on the "Investor Relations" page of Vistra's website. The information on Vistra's website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 10-K. The representations and warranties contained in any agreement that we have filed as an exhibit to this annual report on Form 10-K, or that we have or may publicly file in the future, may contain representations and warranties that may (i) be made by and to the parties thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the parties' risk allocation in the particular transaction, or (iv) be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.
This annual report on Form 10-K and other Securities and Exchange Commission filings of Vistra and its subsidiaries occasionally make references to Vistra (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power or U.S. Gas & Electric, when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, the Vistra financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
|2019 Form 10-K||Vistra's annual report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 28, 2020|
|Ambit or Ambit Energy||Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context|
|ARO||asset retirement and mining reclamation obligation|
|CAA||Clean Air Act|
|CAISO||The California Independent System Operator|
|CARES Act||Coronavirus Aid, Relief, and Economic Security Act|
|CCGT||combined cycle gas turbine|
|CFTC||U.S. Commodity Futures Trading Commission|
|Chapter 11 Cases||Cases in the U.S. Bankruptcy Court for the District of Delaware (Bankruptcy Court) concerning voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) filed on April 29, 2014 (Petition Date) by Energy Future Holdings Corp. (EFH Corp.) and the majority of its direct and indirect subsidiaries, including Energy Future Intermediate Holding Company LLC, Energy Future Competitive Holdings Company LLC and TCEH but excluding Oncor Electric Delivery Holdings Company LLC and its direct and indirect subsidiaries (Debtors). On the Effective Date, subsidiaries of TCEH that were Debtors in the Chapter 11 Cases (TCEH Debtors), along with certain other Debtors that became subsidiaries of Vistra on that date (Contributed EFH Debtors) emerged from the Chapter 11 Cases.|
|CME||Chicago Mercantile Exchange|
|CPUC||California Public Utilities Commission|
|Crius||Crius Energy Trust and/or its subsidiaries, depending on context|
|Dynegy||Dynegy Inc., and/or its subsidiaries, depending on context|
|Dynegy Energy Services||Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/b/a Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy), indirect, wholly owned subsidiaries of Vistra, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers.|
|EBITDA||earnings (net income) before interest expense, income taxes, depreciation and amortization|
|Effective Date||October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases|
|Emergence||emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11 Cases as subsidiaries of a newly formed company, Vistra, on the Effective Date|
|EPA||U.S. Environmental Protection Agency|
|ERCOT||Electric Reliability Council of Texas, Inc.|
|ESS||energy storage system|
|Exchange Act||Securities Exchange Act of 1934, as amended|
|FERC||U.S. Federal Energy Regulatory Commission|
|Fitch||Fitch Ratings Inc. (a credit rating agency)|
|FTC||Federal Trade Commission|
|GAAP||generally accepted accounting principles|
|Homefield Energy||Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers|
|IRC||Internal Revenue Code of 1986, as amended|
|IRS||U.S. Internal Revenue Service|
|ISO||independent system operator|
|ISO-NE||ISO New England Inc.|
|LIBOR||London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market|
|load||demand for electricity|
|LTSA||long-term service agreements for plant maintenance|
|Luminant||subsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management|
|market heat rate||Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas.|
|Merger||the merger of Dynegy with and into Vistra, with Vistra as the surviving corporation|
|Merger Agreement||the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra and Dynegy|
|Merger Date||April 9, 2018, the date Vistra and Dynegy completed the transactions contemplated by the Merger Agreement|
|MISO||Midcontinent Independent System Operator, Inc.|
|MMBtu||million British thermal units|
|Moody's||Moody's Investors Service, Inc. (a credit rating agency)|
|MSHA||U.S. Mine Safety and Health Administration|
|NELP||Northeast Energy, LP, a joint venture between Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., both indirect subsidiaries of Vistra, and certain subsidiaries of NextEra Energy, Inc. Prior to the NELP Transaction, NELP indirectly owned Bellingham NEA facility and the Sayreville facility.|
|NELP Transaction||a transaction among Dynegy Northeast Generation GP, Inc., Dynegy Northeast Associates LP, Inc. and certain subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP partnership in exchange for 100% ownership interest in NJEA, the entity which owns the Sayreville facility|
|NERC||North American Electric Reliability Corporation|
|NJEA||North Jersey Energy Associates, A Limited Partnership|
|NRC||U.S. Nuclear Regulatory Commission|
|NYISO||New York Independent System Operator, Inc.|
|NYMEX||the New York Mercantile Exchange, a commodity derivatives exchange|
|NYSE||New York Stock Exchange|
|Oncor||Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and formerly an indirect subsidiary of EFH Corp., that is engaged in regulated electricity transmission and distribution activities|
|OPEB||postretirement employee benefits other than pensions|
|PJM||PJM Interconnection, LLC|
|Plan of Reorganization||Third Amended Joint Plan of Reorganization filed by the Debtors in August 2016 and confirmed by the Bankruptcy Court in August 2016 solely with respect to the TCEH Debtors and the Contributed EFH Debtors|
|PrefCo||Vistra Preferred Inc.|
|PrefCo Preferred Stock Sale||as part of the Spin-Off, the contribution of certain of the assets of the Predecessor and its subsidiaries by a subsidiary of TEX Energy LLC to PrefCo in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share|
|Public Power||Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers|
|PUCT||Public Utility Commission of Texas|
|PURA||Texas Public Utility Regulatory Act|
|REP||retail electric provider|
|RCT||Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas|
|RTO||regional transmission organization|
|S&P||Standard & Poor's Ratings (a credit rating agency)|
|SEC||U.S. Securities and Exchange Commission|
|Securities Act||Securities Act of 1933, as amended|
|SG&A||selling, general and administrative|
|Spin-Off||the tax-free spin-off from EFH Corp. executed pursuant to the Plan of Reorganization on the Effective Date by the TCEH Debtors and the Contributed EFH Debtors|
|Tax Matters Agreement||Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC|
|TCJA||The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities|
|TCEH or Predecessor||Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of the TCEH Debtors whose major subsidiaries included Luminant and TXU Energy|
|TCEH Debtors||the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases|
|TCEQ||Texas Commission on Environmental Quality|
|TRA||Tax Receivables Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at Emergence (see Note 8 to the Financial Statements)|
|TRE||Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and monitors compliance with ERCOT protocols|
|TriEagle Energy||TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy, Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail sale of electricity to residential and business customers|
|TXU Energy||TXU Energy Retail Company LLC (d/b/a TXU), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers|
|U.S.||United States of America|
|U.S. Gas & Electric||U.S. Gas and Electric, Inc. (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers|
|Value Based Brands||Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers|
|Vistra||Vistra Corp., formerly known as TCEH Corp., and/or its subsidiaries, depending on context. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors emerged from Chapter 11 and became subsidiaries of Vistra Energy Corp. Effective July 2, 2020, Vistra Energy Corp. changed its name to Vistra Corp.|
|Vistra Intermediate||Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra|
|Vistra Operations||Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 11 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities|
|Vistra Operations Credit Facilities||Vistra Operations Company LLC's $5.297 billion senior secured financing facilities (see Note 11 to the Financial Statements)|
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 activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users. We incorporated under Delaware law in 2016. Effective July 2, 2020, we changed our name from Vistra Energy Corp. to Vistra Corp. to distinguish from companies that are involved in exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business powering the communities we serve with safe, reliable power.
We serve approximately 4.5 million customers and operate in 20 states and the District of Columbia. Our generation fleet totals approximately 38,700 MW of generation capacity with a portfolio of natural gas, nuclear, coal, solar and battery energy storage facilities.
Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. Management believes that the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. See Market Discussion below and Note 20 to the Financial Statements for further information concerning the updates to our reportable segments.
Acquisitions and Merger
Ambit Transaction — On November 1, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of Ambit (Ambit Transaction). Because the Ambit Transaction closed on November 1, 2019, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Ambit and its subsidiaries prior to November 1, 2019. See Note 2 to the Financial Statements for a summary of the Ambit Transaction.
Crius Transaction — On July 15, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). Because the Crius Transaction closed on July 15, 2019, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Crius and its subsidiaries prior to July 15, 2019. See Note 2 to the Financial Statements for a summary of the Crius Transaction.
Dynegy Merger Transaction — On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation. Because the Merger closed on April 9, 2018, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy prior to April 9, 2018. See Note 2 to the Financial Statements for a summary of the Merger transaction.
Our business strategy is to deliver long-term stakeholder value through a focus on the following areas:
•Integrated business model. We believe the key factor that distinguishes us from others in the competitive electricity industry is the integrated nature of our business (i.e., pairing our reliable and efficient mining, diversified generation fleet and wholesale commodity risk management capabilities with our retail platform). Our business strategy is guided by our integrated business model because we believe it is our core competitive advantage and differentiates us from our non-integrated competitors by reducing the effects of commodity price movements and contributing to earnings and cash flow stability. Consequently, our integrated business model is at the core of our business strategy.
•Growth and transformation. Vistra's strategy is to grow our business through prudent investments in attractive retail, renewable, and energy storage assets while reducing our carbon footprint and creating a more sustainable company with enduring long-term value for our stakeholders. We expect to meaningfully transform our generation portfolio over the next decade by growing our portfolio of zero-carbon resources, including solar and energy storage, through our Vistra Zero brand and by retiring approximately 7,000 MWs of coal assets between now and year-end 2027. We believe our long-term asset mix will support electric system reliability while providing customers with cost-effective energy that meets their sustainable preferences. Our growth strategy leverages our core capabilities of multi-channel retail marketing in large and competitive markets, operating large-scale, environmentally sensitive, and diverse assets across a variety of fuel technologies, fuel logistics and management, commodity risk management, cost control, and energy infrastructure investing. We intend to opportunistically evaluate the acquisition and development of high-quality energy infrastructure assets and businesses, including renewable energy and battery storage assets as well as retail businesses, that complement our core capabilities and enable us to achieve operational or financial synergies. While we are intent on growing our business and creating value for our stockholders, we are committed to making disciplined investments that are consistent with our focus on maintaining a strong balance sheet and strong liquidity profile. As a result, consistent with our disciplined capital allocation approval process, growth opportunities we pursue must have compelling economic value and align with or enhance our business strategy.
•Disciplined capital allocation. Vistra takes a balanced approach to capital allocation, focusing on maintaining a strong balance sheet, investing prudently in the maintenance of our existing assets and potential growth acquisitions, and returning capital to stockholders. A strong balance sheet helps to ensure Vistra's interest expense is manageable in a variety of wholesale power price environments while giving Vistra access to flexible and diverse sources of liquidity. We prudently make necessary capital investments to maintain the safety and reliability of our facilities while also investing in new technologies when economic, including solar assets and battery storage systems, resulting in a continued modernization of Vistra's generation fleet. Because we believe cost discipline and strong management of our assets and commodity positions are necessary to deliver long-term value to our stakeholders, we generally make capital allocation decisions that we believe will lead to attractive cash returns on investment, including by returning capital to our stockholders through quarterly dividends and our share repurchase program (see Note 14 to the Financial Statements).
•Superior customer service. Through our retail brands, including TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric, we serve the retail electricity and natural gas needs of end-use residential, small business, commercial and industrial electricity customers through multiple sales and marketing channels. In addition to benefitting from our integrated business model, we leverage our brands, our commitment to a consistent and reliable product offering, the backstop of the electricity generated by our generation fleet, our wholesale commodity risk management operations and our strong customer service to differentiate our products and services from our competitors. We strive to be at the forefront of innovation with new offerings and customer experiences to reinforce our value proposition. We maintain a focus on solutions that give our customers choice, convenience and control over how and when they use electricity and related services, including TXU Energy's Free Nights and Solar Days residential plans, MyEnergy DashboardSM, TXU Energy's iThermostat product and mobile solution, the TXU Energy Rewards program, the TXU Energy Green UpSM renewable energy credit program and a diverse set of solar options. Our focus on superior customer service will guide our efforts to acquire new residential and commercial customers, serve and retain existing customers and maintain valuable sales channels for our electricity generation resources. We believe our customer service, products and trusted brands will result in high residential customer retention rates, particularly in Texas where our TXU Energy brand has maintained its residential customers in a highly competitive retail market.
•Excellence in operations while maintaining an efficient cost structure. We believe that operating our facilities in a safe, reliable, environmentally compliant, and cost-effective and efficient manner is a foundation for delivering long-term stakeholder value. We also believe stakeholder value is increased as a result of making disciplined investments that enable our generation facilities to operate not only effectively and efficiently, but also safely, reliably and in an environmentally compliant manner. We believe that an ongoing focus on operational excellence and safety is a key component to success in a highly competitive environment and is part of the unique value proposition of our integrated model. Additionally, we are committed to optimizing our cost structure, reducing our debt levels and implementing enterprise-wide process and operating improvements without compromising the safety of our communities, customers and employees. We believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our operations.
•Integrated hedging and commercial management. Our commercial team is focused on managing risk, through opportunistic hedging, and optimizing our assets and business positions. We actively seek to manage our exposure to wholesale electricity prices in markets in which we operate, on an integrated basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter financial contracts, term, day-ahead and real-time market transactions, and bilateral contracts with other wholesale market participants, including other power generators and end-user electricity customers. We seek to hedge near-term cash flows and optimize long term value through hedging and forward sales contracts. We believe our integrated hedging and commercial management strategy, in combination with a strong balance sheet and strong liquidity profile, will provide a long-term advantage through cycles of higher and lower commodity prices.
•Corporate responsibility and citizenship. We are committed to providing safe, reliable, cost-effective and environmentally compliant electricity for the communities and customers we serve. We strive to improve the quality of life in the communities in which we operate. We are also committed to being a good corporate citizen in the communities in which we conduct operations. We and our employees are actively engaged in programs intended to support and strengthen the communities in which we conduct operations. Our foremost giving initiatives are through the United Way, TXU Energy Aid and Ambit Cares campaigns. TXU Energy Aid serves as an integral resource for social service agencies that assist those in need across Texas pay their electricity bills. Ambit Cares partners with Feeding America® to assist those in need across the U.S. by fighting hunger through a network of food banks.
Dividend Declaration — In February 2021, the Board declared a quarterly dividend of $0.15 per share that will be paid in March 2021.
Change in Principal Financial Officer — In December 2020, James A. Burke, who previously served as the Company's Executive Vice President and Chief Operating Officer, was elected as President and Chief Financial Officer and assumed the duties of serving as the Company's Principal Financial Officer following the resignation of David A. Campbell from his roles as Chief Financial Officer and Principal Financial Officer of the Company.
Share Repurchase Program — 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 January 1, 2021, at which time the prior share repurchase plan and all authorized amounts remaining thereunder terminated as of such date. From January 1, 2021 through February 23, 2021, 5,902,720 shares of our common stock had been repurchased under the Share Repurchase Program for $125 million. See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program and the Prior Share Repurchase Program.
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 CODM makes operating decisions, assesses performance and allocates resources. Management believes that the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The following is a summary of the updated segments:
•The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments. As we announced significant plant closures in the third quarter of 2020, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.
•The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes operations in PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.
•The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporate and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 3 to the Financial Statements), the Company expects to expand its operations in the West segment.
In addition, the ERCOT segment was renamed the Texas segment. There were no changes to the Retail and Asset Closure segments. All historical segment results within these consolidated financial statements have been recast to be in alignment with our new segmentation. See Note 20 to the Financial Statements for further information concerning reportable segments.
Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs)
Separately, ISOs/RTOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system. ISOs/RTOs administer energy and ancillary service markets in the short term, which usually consists of day-ahead and real-time markets. Several ISOs/RTOs also ensure long-term planning reserves through monthly, semiannual, annual and multi-year capacity markets. The ISOs/RTOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, bid and price limits or other similar mechanisms. NERC regions and ISOs/RTOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and ISOs/RTOs, their respective roles and responsibilities do not generally overlap.
In ISO/RTO regions with centrally dispatched market structures (e.g., ERCOT, PJM, ISO-NE, NYISO, MISO, and CAISO), all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location. Different zones or locations within the same ISO/RTO may produce different prices respective to other zones within the same ISO/RTO due to transmission losses and congestion. For example, a less efficient and/or less economical natural gas-fueled unit may be needed in some hours to meet demand. If this unit's production is required to meet demand on the margin, its offer price will set the market clearing price that will be paid for all dispatched generation in the same zone or location (although the price paid at other zones or locations may vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the market. Generators will receive the location-based marginal price for their output.
The Retail segment is engaged in retail sales of electricity, natural gas and related services to approximately 4.5 million customers. Substantially all of these activities are conducted by TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 U.S. states and the District of Columbia.
The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.4 million customers in ERCOT. We are an active participant in the competitive ERCOT retail market and continue to be a market leader, which we believe is driven by, among other things, strong brands, innovative products and services and excellent customer service. As of December 31, 2020, we provided electricity to approximately 31% of the residential customers in ERCOT and for approximately 15% of business customers' demand. We believe that we have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power products and solutions to our customers, which give our customers choice, convenience and control over how and when they use electricity and related services. Our retail business also offers a comprehensive suite of green products and services, including 100% wind and solar options, as well as thermostats, dashboards and other programs designed to encourage reduced consumption and increased energy efficiency.
Our integrated power generation and wholesale operation allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost. The integrated model enables us to structure products and contracts in a way that offers significant value compared to stand-alone retail electric providers. Additionally, our wholesale commodity risk management operations protect our retail business from power price volatility by allowing us to bypass bid-ask spread in the market (particularly for illiquid products and time periods) and achieve lower collateral costs for our retail business as compared to other, non-integrated retail electric providers. Moreover, our retail business reduces, to some extent, the exposure of our wholesale generation business to wholesale power price volatility. This is because the retail load requirements of our retail operations provide a natural offset to the length of Luminant's generation portfolio thereby reducing the exposure to wholesale power price volatility as compared to a non-integrated independent power producer.
Outside of ERCOT, we also serve residential, municipal, commercial and industrial customers substantially through our Homefield Energy, Dynegy Energy Services, Public Power, U.S. Gas & Electric and Ambit Energy retail businesses, through which we provide retail electricity, natural gas and related services to approximately 2.1 million customers in 18 states and the District of Columbia.
Our Texas segment is comprised of 18 power generation facilities totaling 17,623 MW of generation capacity in ERCOT. We also operate a 10 MW battery energy storage system (ESS) at our Upton 2 solar facility. In September 2020, we announced the planned development of 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas with estimated commercial operation dates between the summer of 2021 and the fall of 2022. See Note 3 to the Financial Statements for a summary of our solar and battery energy storage projects.
|ISO/RTO||Technology||Primary Fuel||Number of Facilities||Net Capacity (MW)|
|ERCOT||CT or ST||Natural Gas||7||3,455|
|Total Texas Segment||18||17,623|
ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 86,000 MW of installed generation capacity to approximately 26 million Texas customers, representing approximately 90% of the state's electric load.
As an energy-only market, ERCOT's market design is distinct from other competitive electricity markets in the U.S. Other markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/or capacity markets. In contrast, ERCOT's resource adequacy is predominately dependent on energy-market price signals. In 2014, ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to which wholesale electricity prices in the real-time electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating a price adder. When operating reserves drop to 2,000 MW or less, the ORDC automatically adjusts power prices to the established value of lost load (VOLL), which is set at $9,000/MWh which is equal to the system-wide offer cap. In both March 2019 and March 2020, ERCOT implemented 0.25 standard deviation shifts in the loss of load probability calculation using a single blended ORDC curve; these changes resulted in a more rapid escalation in power prices as operating reserves fall below defined thresholds. ERCOT calculates the "peaker net margin" based on revenues a hypothetical unhedged peaking unit would collect in the market. If the peaker net margin exceeds a certain threshold, the system-wide offer cap is reduced for the remainder of the calendar year. Historically, high demand due to elevated temperatures in the summer months, combined with underperformance of wind generation, has created the conditions during which the ORDC contributes meaningfully to power prices. Extreme weather conditions can also lead to scarcity conditions regardless of season. Other than during periods of "scarcity pricing," the price of power is typically set by natural gas-fueled generation facilities; as a result, historically low natural gas prices have had a corresponding impact on wholesale prices (see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Key Operational Risks and Challenges).
Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead market is a voluntary, financial electricity market conducted the day before each operating day in which generators and purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a physical market in which electricity is dispatched and priced in five-minute intervals. The day-ahead market provides market participants with visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the real-time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow market participants to manage their risk profile by adjusting their participation in each market. In addition, ERCOT uses ancillary services to maintain system reliability, including regulation service, responsive reserve service and non-spinning reserve service. Ancillary services are provided by generators to help maintain the stable voltage and frequency requirements of the transmission system. Because ERCOT has one of the highest concentrations of wind capacity generation among U.S. markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind production, making ERCOT more vulnerable to periods of generation scarcity.
Our East segment is comprised of 21 power generation facilities in 10 states totaling 12,093 MW of generating capacity in PJM, ISO-NE and NYISO.
|ISO/RTO||Technology||Primary Fuel||Number of Facilities||Net Capacity (MW)|
|Total East Segment||21||12,093|
PJM — PJM is an RTO that manages the flow of electricity from approximately 180,000 MW of installed generation capacity to approximately 65 million customers in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
Like ERCOT, PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing a locational marginal pricing (LMP) methodology which calculates a price for every generator and load point within PJM. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services. PJM also administers a forward capacity auction, the Reliability Pricing Model (RPM), which establishes a long-term market for capacity. We have participated in RPM auctions for years up to and including PJM's planning year 2021-2022, which ends May 31, 2022. Due to a change in auction rules, PJM's next RPM auction, for planning year 2022-2023, was delayed until May 2021. We also enter into bilateral capacity transactions. PJM's Capacity Performance (CP) rules were designed to improve system reliability and include penalties for under-performing units and reward for over-performing units during shortage events. Full transition of the capacity market to CP rules occurred in planning year 2020-2021. An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and to identify improper behavior by any entity.
ISO-NE — ISO-NE is an ISO that manages the flow of electricity from approximately 31,000 MW of installed generation capacity to approximately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island and Maine.
ISO-NE dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the participating states in ISO-NE and are largely influenced by transmission constraints and fuel supply. ISO-NE offers a forward capacity market where capacity prices are determined through auctions. Performance incentive rules have the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level.
NYISO — NYISO is an ISO that manages the flow of electricity from approximately 40,000 MW of installed generation capacity to approximately 20 million New York customers.
NYISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the regional zones in the NYISO and are largely influenced by transmission constraints and fuel supply. NYISO offers a forward capacity market where capacity prices are determined through auctions. Strip auctions occur one to two months prior to the commencement of a six-month seasonal planning period. Subsequent auctions provide an opportunity to sell excess capacity for the balance of the seasonal planning period or the upcoming month. Due to the short-term nature of the NYISO-operated capacity auctions and a relatively liquid bilateral market for NYISO capacity products, our Independence facility sells a significant portion of its capacity through bilateral transactions. The balance is cleared through the seasonal and monthly capacity auctions.
Our West segment is comprised of two power generation facilities totaling 1,185 MW of generation capacity and one battery ESS totaling 300 MW in CAISO, all of which are located in California.
|ISO/RTO||Technology||Primary Fuel||Number of Facilities||Net Capacity (MW)|
|Total West Segment||3||1,485|
In addition, we are developing approximately 136 MW of battery energy storage systems at our Moss Landing and Oakland facilities that are expected to enter commercial operations in 2021-2022 (see Note 3 to the Financial Statements).
CAISO — CAISO is an ISO that manages the flow of electricity to approximately 32 million customers primarily in California, representing approximately 80% percent of the state's electric load.
Energy is priced in CAISO utilizing an LMP methodology. The capacity market is comprised of Generic, Flexible and Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission. Unlike other centrally cleared capacity markets, the resource adequacy market in California is a bilaterally traded market. In November 2016, CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market. The voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a modification to the Capacity Procurement Mechanism (CPM) and provides another avenue to sell RA capacity.
Our Sunset segment is comprised of 10 power generation facilities totaling 7,486 MW of generating capacity in MISO, PJM and ERCOT. The Sunset segment represents plants with announced retirement plans between 2022 and 2027 that were previously reported in the ERCOT, PJM and MISO segments No separate segment previously existed to differentiate operating plants with defined retirement plans from operating plants without defined retirement plans. See Note 4 to the Financial Statements for more information related to these planned generation retirements.
|ISO/RTO||Technology||Primary Fuel||Number of Facilities||Net Capacity (MW)|
|Total Sunset Segment||10||7,486|
See Texas Segment above for a discussion of the ERCOT ISO and East Segment above for a discussion of the PJM RTO.
MISO — MISO is an RTO that manages the flow of electricity from approximately 198,000 MW of installed generation capacity to approximately 42 million customers in all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana, Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota and Manitoba, Canada.
MISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the regional zones in MISO and are largely influenced by transmission constraints and fuel supply. An independent market monitor is responsible for evaluating the performance of the markets and identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of the markets.
MISO administers a one-year Planning Resource Auction for the next planning year from June 1st of the current year to May 31st of the following year. We participate in these auctions with open capacity that has not been committed through bilateral or retail transactions. We also participate in the MISO annual and monthly financial transmission rights auctions to manage the cost of our transmission congestion, as measured by the congestion component of the LMP price differential between two points on the transmission grid across the market area.
Joppa, which is partially interconnected to MISO and partially within the Electric Energy, Inc. (EEI) control area, is interconnected to the Tennessee Valley Authority and Louisville Gas and Electric Company. Joppa primarily sells its capacity and energy to MISO.
Our wholesale commodity risk management group is responsible for dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our retail customer and wholesale sales opportunities. Market demand, also known as load, faced by electric power systems, such as those we operate in, varies from moment to moment as a result of changes in business and residential demand, which is often driven by weather. Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric power system that occurs throughout the day, which is typically satisfied by baseload generating units with low variable operating costs. Baseload generating units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually low. Intermediate/load-following generating units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages. Peak daily loads may be satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load following units and peaking units are dispatched into the ISO/RTO grid in order from lowest to highest variable cost. Price formation is typically based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time.
Our commodity risk management group also enters into electricity, gas and other commodity derivative contracts to reduce exposure to changes in prices primarily to hedge future revenues and fuel costs for our generation facilities and purchased power costs for our Retail segment.
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results are impacted by extreme or sustained weather conditions and may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme winter weather have made, and may make such fluctuations more pronounced. The pattern of this fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.
Competition in the markets in which we operate is impacted by electricity and fuel prices, congestion along the power grid, subsidies provided by state and federal governments for new and existing generation facilities, new market entrants, construction of new generating assets, technological advances in power generation, the actions of environmental and other regulatory authorities, and other factors. We primarily compete with other electricity generators and retailers based on our ability to generate electric supply, market and sell electricity at competitive prices and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities to deliver electricity to end-users. Competitors in the generation and retail power markets in which we participate include numerous regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities, independent power producers, REPs and other energy marketers. See Item 1A. Risk Factors for additional information concerning the risks faced with respect to the markets in which we operate.
Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in Texas for approximately 19 years, is registered and protected by trademark law and is the only material intellectual property asset that we own. We have also acquired the trade names for Ambit Energy, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric through the Ambit Transaction, Crius Transaction and the Merger, as the case may be. As of December 31, 2020, we have reflected intangible assets on our balance sheet for our trade names of approximately $1.374 billion (see Note 6 to the Financial Statements).
Human Capital Resources
As a key component of our core principle that we work as a team, Vistra believes our most valuable asset is our talented, dedicated and diverse group of employees who work together to achieve our objectives, and our top priority is ensuring their safety. One of Vistra's core principles is that we care about our key stakeholders, including our employees. We invest in our people through numerous development and training opportunities, engaging employee programs and generous benefit and wellness offerings.
As of December 31, 2020, we had approximately 5,365 full-time employees, including approximately 1,640 employees under collective bargaining agreements.
Vistra's mindset around safety is exemplified by our motto: Best Defense. Everyone wins. No one gets hurt. Our safety culture revolves around people and human performance. We place a high importance on continuous improvement, along with a keen focus on numerous learning and error-prevention tools. To facilitate a learning environment, our various operating plants share their investigations and learnings of all safety events with all operations employees on weekly calls. The information is presented by front-line employees and supported by management. The lessons from each event are shared across the fleet to prevent similar incidents at other locations. All personnel at Vistra locations are encouraged to be actively involved in the safety process. Managers are required to participate in safety engagements with staff to enable constant communication and sustained interaction. In 2020, the generation fleet conducted more than 57,000 leadership safety engagements across the fleet continuing our employee driven safety program focused on engagement of all employees.
Our focus on reducing the severity of injuries for both our employees and contractors who work with us has shown positive results. In 2020, we did not have any serious injuries or fatalities to our Vistra employees. Although we do not focus on recordable incidents, our Total Recordable Incident rate (TRIR) for the company was 0.61, better than the first quartile as compared to the Edison Electric Institute (EEI) 2019 Total Company Injury data. We encourage near-miss reporting and review of events to promote a learning environment. In 2020, safety learning calls were held every week where near miss and safety events were reviewed by our operating teams to promote learning across the fleet.
All Vistra employees are covered by our safety program. Office employees are required to complete periodic training on safety topics through our online learning management system. Power plant employees are required to complete trainings based on job function, which is also tracked through our central learning management system. In addition, the Company engages an independent third-party conformity assessment and certification vendor to manage adherence to our safety standards for all vendors and contractors who work at our plants. In addition, we work closely with our suppliers and contractors to ensure our safety practices are upheld.
Our generation fleet has a total of 12 plants that have been awarded the Voluntary Protection Program (VPP) Star designation by the OSHA for superior demonstration of effective safety and health management systems and for maintaining injury and illness rates below the national averages for our industry. Two additional plants submitted applications in 2020 and are awaiting review by the OSHA. VPP Star status is the highest designation of OSHA's Voluntary Protection Programs. The achievement recognizes employers and workers who have implemented effective safety and health management systems and maintain injury and illness rates below national Bureau of Labor Statistics averages for their respective industries. These sites are self-sufficient in their ability to control workplace hazards and are reevaluated every three to five years. Additionally, 23 of our power plants and mine locations have adopted a proactive Behavior Based Safety approach to safety which focuses on identifying and providing feedback on at-risk behaviors observed.
In 2020, our Kosse mine site was recognized for the Sentinels of Safety Award by the National Mining Association, the highest distinction for mine safety. This is the second time Kosse has been awarded in the last three years showing the commitment to safety at our mining operations.
Diversity, Equity and Inclusion
We recognize the value of having a diverse and inclusive workforce. Our diversity includes all the ways we differ, such as age, gender, ethnicity and physical appearance, as well as underlying differences such as thoughts, styles, religions, nationality, education and numerous other traits. Creating and maintaining an environment where differences are valued and respected enhances our ability to recruit and retain the best talent in the marketplace. As we continue to promote and maintain an environment that fosters creativity, productivity and mutual respect, Vistra becomes the employer of choice by recognizing and using the value that each individual brings to the workplace.
Vistra's diversity is evolving and management is leading by example. Overall, 28% of the Company's workforce is ethnically diverse. Women currently hold 26% of the Company's senior management positions, and ethnically diverse employees represent 23% of senior management. In 2020, the Board of Directors increased diversity as well. Currently three of the ten board members are women, and two of the ten board members are ethnically diverse.
During 2020, we launched multiple initiatives to unlock the full potential of our people - and our company - through our diversity, equity, and inclusion efforts. We formalized a Diversity, Equity and Inclusion Advisory Council and expanded our Employee Resource Groups (ERG) to promote the appreciation of and communicate awareness of diverse employee groups and communities and their contribution to the overall success of the organization, both internally and externally. New ERGs will join existing ERGs such as Vistra's Women's Information Network, Opportunities for Professional Enrichment and Networking, Parents at Work, Veterans and Toastmasters. Further initiatives were launched to support the education, recruitment and retention of current and future employees, with particular emphasis being placed on driving equal access to opportunities throughout the organization. We contracted with Basic Diversity, Inc. to conduct an assessment of Vistra's diversity, equity and inclusion training needs, and as part of our commitment to diversity, equity and inclusion, we named our first Chief Diversity Officer in January 2021.
Training and Development
We believe the development of employees at all levels is critical to Vistra's current and future success. We have launched key programs to develop leaders at all levels of the organization, including monthly leader meetings for director-level employees focusing on gaining a deeper understanding of Vistra's strategy, developing cross-functional relationships and interacting with senior leadership of the company. Essentials in Leadership provides first time managers with skills to lead organizations in situational leadership, business acumen, identification of communication styles and inclusive communication practices, and exposes them to best practices from across the company. We also revised multiple leadership programs to continue virtually during the COVID-19 pandemic.
Vistra also provides many other training and development programs to help grow and develop employees at every level, including online learning platform courses, learning management system courses, recorded webinars and presentations, self-paced development and employee-specific skill training. Thousands of web-based targeted courses are available to all employees, and the company further supports employees in completing thousands of hours of professional training to support continuing education requirements for their respective professional licenses, including accounting, legal and nuclear. We also support a variety of employee-initiated and -led programs based on demographics, interests and purpose, including Women's Information Network, Opportunities for Professional Enrichment and Networking, Parents at Work, TXU Green Team and Toastmasters.
Maintaining attractive benefits and pay are important for recruiting and retaining talent. We are committed to maintaining an equitable compensation structure, including performing annual salary reviews by employee category level within significant locations of operations. Eligible full- and part-time employees are provided access to medical, prescription drug, dental, vision, life insurance, accidental death and dismemberment and long-term disability coverage. Regular full-time employees are eligible for short-term disability benefits, and all employees are eligible for the employee assistance program, parental leave, maternity leave and a 401(k) plan through which the Company matches employee contributions up to 6%.
We believe a healthy workforce leads to greater well-being at work and at home. Our healthcare plans are designed to reward employees for getting annual physicals and cancer screenings. Fitness centers in multiple facilities offer cardio equipment, a selection of free weights and exercise mats. Our employee-led wellness team engages our people to get active and support causes that promote healthy living. With support from the company, the wellness team covers the registration costs for employees to participate in more than a dozen running events each year. Additionally, the team hosts quarterly blood drives and recruits participants for our cycling and soccer teams.
Environmental Regulations and Related Considerations
We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. See Item 1A. Risk Factors for additional discussion of risks posed to us regarding regulatory requirements. See Note 13 to the Financial Statements for a discussion of litigation related to EPA reviews.
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.
There is increasing attention and interest domestically and internationally about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide (CO2), contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarily by our coal/lignite-fueled-generation plants, represent the substantial majority of our total GHG emissions. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. We estimate that our generation facilities produced approximately 103 million short tons of CO2 in 2020.
We have already taken or announced significant steps to transition the fuel-mix and reduce the emissions profile of our generation fleet, including:
•Solar Development Projects — In 2018, we began commercial operation of our 180 MW Upton 2 solar facility. In September 2020, we announced the planned development of 668 MW of solar generation facilities in Texas that are expected to begin commercial operations during 2021-2022.
•Battery Energy Storage Projects — In 2018, our 10 MW battery energy storage system (ESS) at our Upton 2 solar facility in Texas commenced operations. Between 2018 and 2020, we announced the planned development of approximately 436 MW of various ESSs in California that are expected to enter commercial operations in 2021-2022. In September 2020, we announced the planned development of a 260 MW ESS in Texas that is expected to enter commercial operation in 2022.
•Acquisition of CCGTs — In 2016 and 2017, we acquired 4,042 MW of CCGTs in Texas. In 2018, we acquired 15,448 MW of CCGTs across various ISOs/RTOs in connection with the Merger.
•Retirements of Coal Generation — In 2018, we retired 4,167 MW of lignite/coal-fueled generation facilities in Texas. In 2019, we retired 2,068 MW of coal-fueled generation facilities in Illinois. We expect to retire an additional 7,486 MW of coal-fueled generation facilities in Illinois, Ohio and Texas no later than year-end 2027.
See Note 3 to the Financial Statements for discussion of our solar and battery energy storage projects and Note 4 to the Financial Statements for discussion of our retirement of generation facilities.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address 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 new rule that replaces the Clean Power Plan, the Affordable Clean Energy rule, discussed below. In September 2019, the D.C. Circuit Court granted petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.
In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule develops emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. The ACE rule set a deadline of July 2022 for states to submit their plans for regulating GHG emissions from existing facilities. States where we operate coal plants (Texas, Illinois and Ohio) have begun the development of their state plans to comply with the rule. Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power Plan in the D.C. Circuit Court, and the D.C. Circuit Court heard argument on those issues in October 2020. In January 2021, the D.C. Circuit Court vacated the ACE rule and remanded the rule to the EPA for further action. In its decision, the D.C. Circuit Court concluded that the EPA's basis for repealing the Clean Power Plan and adopting the ACE rule was not supported by the Clean Air Act. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units. Vistra submitted comments on that proposed rulemaking in March 2019. In January 2021, the EPA, just prior to the transition to the Biden administration, issued a final rule setting forth a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. The final rule exclude 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. The ACE rule and the rule on significant contribution are subject to the Environment Executive Order discussed above.
State Regulation of GHGs
Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.
Regional Greenhouse Gas Initiative (RGGI) — RGGI is a state-driven GHG emission control program that took effect in 2009 and was initially implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants. The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period.
In December 2017, the RGGI states released an updated model rule with changes to the CO2 budget trading program, including an additional 30 percent reduction in the CO2 annual cap by the year 2030, relative to 2020 levels.
Our generating facilities in Connecticut, Maine, Massachusetts, New Jersey and New York emitted approximately 7 million tons of CO2 during 2020. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2020 was approximately $8.11 per allowance. The spot market price of RGGI allowances required to operate our affected facilities during 2021 was $8.34 per allowance on February 23, 2021. While the cost of allowances required to operate our RGGI-affected facilities is expected to increase in future years, we expect that the cost of compliance would be reflected in the power market, and the actual impact to gross margin would be largely offset by an increase in revenue.
Massachusetts — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final rules establishing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation units. The rules establish an allowance trading system under which the annual aggregate electricity generation unit sector cap on CO2 emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. MassDEP allocated emission allowances to affected facilities for 2018. Beginning in 2019, the allocation process transitioned to a competitive auction process whereby allowances are partially distributed through a competitive auction process and partially distributed based on the process and schedule established by the rule. Beginning in 2021, all allowances will be distributed through the auction. Limited banking of unused allowances is allowed.
Virginia — In May 2019, the Virginia Department of Environmental Quality issued a final rule to adopt a carbon cap-and trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020. The program is based on the RGGI proposed 2017 model rule and will link Virginia to RGGI beginning in 2021.
New Jersey — In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental agency and public utilities board to begin the process of rejoining RGGI, and New Jersey formally rejoined RGGI in June 2019. In June 2019, New Jersey adopted two rules that govern New Jersey's reentry into the RGGI auction and distribution of the RGGI auction proceeds.
California — Our assets in California are subject to the California Global Warming Solutions Act, which required the California Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establishing a new statewide GHG reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80 percent below 1990 levels. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure allowances for our affected assets.
In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB adopted amendments to its cap-and-trade regulations that, among other things, established a framework for extending the program beyond 2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January 2018.
The Clean Air Act (CAA)
The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled electricity generation plants meet certain pollutant emission standards and have sufficient emission allowances to cover sulfur dioxide (SO2) emissions and in some regions nitrogen oxide (NOX) emissions.
In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission reduction technologies. These technologies include flue gas desulfurization (FGD) systems, dry sorbent injection (DSI), baghouses and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective catalytic reduction (SCR) systems, low-NOX burners and/or overfire air systems on all units. Additionally, our MISO coal-fueled facilities mainly use low sulfur coal, which, prior to combustion, goes through a refined coal process to further reduce NOX and mercury emissions. In 2018, we received approval to use refined coal at some of our Texas coal-fueled facilities.
Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory class I federal areas which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, certain electricity generation units built between 1962 and 1977 are subject to BART standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area. BART reductions of SO2 and NOX are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR or other approved alternative program.
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 Fifth Circuit Court as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA in the Fifth Circuit Court action. In March 2018, the Fifth Circuit Court abated its proceedings pending conclusion of the EPA's reconsideration process. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. In October 2020, environmental groups petitioned for review of this rule in both the D.C. Circuit Court and the Fifth Circuit Court. Briefing is underway on the proper venue for any challenge to the final rule. As finalized, we expect that we will be able to comply with the rule. The BART rule is subject to the Environment Executive Order discussed above.
Affirmative Defenses During Malfunctions
In May 2015, the EPA finalized a rule requiring 36 states, including Texas, Illinois and Ohio, to remove or replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during upset events and unplanned maintenance and startup and shutdown events, referred to as the SIP Call. Various parties (including Luminant, the State of Texas and the State of Ohio) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. In April 2017, the D.C. Circuit Court ordered the case to be held in abeyance. In April 2019, the EPA Region 6 proposed a rule to withdraw the SIP Call with respect to the Texas affirmative defense provisions. We submitted comments on that proposed rulemaking in June 2019. In February 2020, the EPA issued the final rule withdrawing the Texas SIP Call. In April 2020, a group of environmental petitioners, including the Sierra Club, filed a petition in the D.C. Circuit Court challenging the EPA's action with respect to Texas. Briefing is currently underway in the challenge to the EPA's action with respect to Texas. In October 2020, the EPA issued new guidance on the inclusion of startup, shutdown and malfunction (SSM) provisions in SIPs, which is intended to supersede the policy in the multi-state SIP Call. The guidance provides that the SIPs may contain provisions for SSM events if certain conditions are met. The EPA SSM guidance is subject to the Environment Executive Order discussed above.
Illinois Multi-Pollutant Standards (MPS)
In August 2019, changes proposed by the Illinois Pollution Control Board to the MPS rule, which places 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. See Note 4 to the Financial Statements for information regarding the retirement of these four plants.
National Ambient Air Quality Standards (NAAQS)
The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has established NAAQS for six such pollutants, including SO2 and ozone. Each state is responsible for developing a SIP that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities.
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.
The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Various parties challenged the 2015 ozone NAAQS; however, in August 2019, the D.C. Circuit Court generally upheld the 2015 ozone NAAQS but remanded the secondary ozone standard to the EPA for reconsideration. In November 2017, the EPA issued an initial round of area designations for the 2015 ozone NAAQS, designating most areas of the U.S. as attainment/unclassifiable. Several states and other groups have filed lawsuits seeking to compel the EPA to complete designations for all areas of the country. In December 2017, the EPA notified states of expected nonattainment area designations for the 2015 ozone NAAQS. Those areas include areas concerning our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facility in Illinois and our Wise, Ennis and Midlothian facilities in Texas. In June 2018, the EPA finalized these designations as marginal nonattainment areas.
In November 2017, the EPA denied a petition from nine northeastern states to add several states, including Illinois and Ohio, to the Ozone Transport Region. Eight of the northeastern states filed a petition for judicial review challenging the EPA's action in the D.C. Circuit Court. In April 2019, the D.C. Circuit Court denied the states' petition for review, upholding the EPA's denial. Additionally, in January 2018, New York and Connecticut filed a lawsuit against the EPA in the Southern District of New York seeking to compel the agency to issue a FIP for the 2008 ozone NAAQS that addresses sources in five upwind states, including Illinois. The plaintiffs filed a motion for summary judgment on the matter in April 2018, and the court granted that motion in June 2018. As a result, the EPA was required to propose an action to address the 2008 ozone NAAQS by June 29, 2018, and promulgate a final action by December 6, 2018. In January 2019, the plaintiffs informed the district court that the EPA had satisfied its deadlines in accordance with the court's order. However, in January 2019, New York, Connecticut, four other states, and the City of New York filed a separate petition for review in the D.C. Circuit Court challenging the final action the EPA took in December 2018 consistent with the Southern District of New York's order. In October 2019, the D.C. Circuit Court vacated the final rule, and in February 2020, New Jersey, Connecticut, three other states and the City of New York filed a lawsuit against the EPA in the Southern District of New York to compel the EPA to promulgate a fully-compliant FIP to address the 2008 ozone NAAQS in light of the D.C. Circuit Court's vacatur. In July 2020, the U.S. District Court for the Southern District of New York ordered the EPA to issue a final rulemaking fully addressing the 2008 ozone NAAQS by March 15, 2021. The EPA proposed its action to address the outstanding 2008 ozone NAAQS obligations in October 2020. Vistra subsidiaries filed comments on that rulemaking in December 2020. These actions are subject to the Environment Executive Order discussed above.
In November 2016, the State of Maryland petitioned the EPA to impose additional NOX emission control requirements on 36 electricity generation units in five upwind states, including our Zimmer facility, that the State alleges are contributing to nonattainment with the 2008 ozone NAAQS in Maryland. In the fall of 2017, Maryland and several environmental groups filed lawsuits against the EPA seeking to compel the Agency to act on the State's petition. In October 2018, the EPA took final action denying the Maryland petition, and Maryland filed a petition for review of the EPA's denial in the D.C. Circuit Court. In May 2020, the D.C. Circuit Court largely upheld the EPA's denial of Maryland's petition but granted Maryland's petition with respect to the EPA's treatment of sources with non-catalytic controls and remanded the issue to the EPA. Given that the Zimmer facility utilizes SCR technology to control NOX emissions, we do not believe that the EPA's action on remand could cause a material adverse impact on our future financial results.
In March 2018, the State of New York petitioned the EPA to find that emissions from hundreds of sources in nine states, including Illinois, Ohio, Virginia and West Virginia are significantly contributing to New York's nonattainment and interfering with New York's maintenance of the 2008 and 2015 ozone NAAQS. On October 18, 2019, the EPA took final action denying New York's petition. On October 29, 2019, New York, New Jersey and the City of New York filed a petition for review of the EPA's denial of the Section 126 petition. In July 2020, the D.C. Circuit Court vacated the EPA's denial and remanded the action to the EPA for further proceedings.
Coal Combustion Residuals (CCR)/Groundwater
The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fueled plants has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste.
Coal Combustion Residuals
The EPA's CCR rule, which took effect in October 2015, establishes minimum federal requirements for the construction, retrofitting, operation and closure of, and corrective action with respect to, existing and new CCR landfills and surface impoundments, as well as inactive CCR surface impoundments. The requirements include location restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping and notification. The rule allows existing CCR surface impoundments to continue to operate for the remainder of their operating life, but generally would require closure (i.e., cessation of placement of CCR material and corrective action necessary to reach the standards provided in the CCR rule and applicable state rules) if groundwater monitoring demonstrates that the CCR surface impoundment is responsible for exceedances of groundwater quality protection standards or the CCR surface impoundment does not meet location restrictions or structural integrity criteria. The deadlines for beginning and completing closure vary depending on several factors. Several petitions for judicial review of the CCR rule were filed. The Water Infrastructure Improvements for the Nation Act (the WIIN Act), which was enacted in December 2016, provides for EPA review and approval of state CCR permit programs.
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 our subsidiary Dynegy Midwest Generation, LLC (DMG), alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. 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 Illinois Pollution Control Board (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 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, and we expect the rulemaking process should be completed by early 2021. Under the proposed rule, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The proposed rule does not mandate closure by removal at any site. Public hearings for the proposed rule were held in August 2020 and September 2020. We expect that the rule will be finalized by March 2021.
For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. Until the revisions to the Illinois coal ash rulemaking are finalized and we undertake further site-specific evaluations required by each program we will not know the full range of costs of groundwater remediation, if any, that ultimately may be required under those rules. However, the currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO balances, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.
The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion, impoundment and withdrawal of water for cooling and other purposes and the discharge of wastewater (including storm water) from our facilities. We believe our facilities are presently in material compliance with applicable federal and state requirements relating to these activities. We believe we hold all required permits relating to these activities for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals.
Cooling Water Intake Structures — Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities became effective in 2014. This provision generally requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. Although the rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level.
At this time, we estimate the cost of our compliance with the cooling water intake structure rule to be minimal at our Illinois plants due to the planned retirements of those plants by 2027. Our estimate could change materially depending upon a variety of factors, including site-specific determinations made by states in implementing the rule, the results of impingement and entrainment studies required by the rule, the results of site-specific engineering studies and the outcome of litigation concerning the rule and potential plant retirements.
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.
The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily using dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the U.S. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.
Item 1A.RISK FACTORS
Summary of Risk Factors
The following summarizes the principal factors that make an investment in our company speculative or risky, all of which are more fully described in the Risk Factors section below. This summary should be read in conjunction with the Risk Factors section and should not be relied upon as an exhaustive summary of the material risks facing our business. The following factors could result in harm to our business, financial condition, results of operations, cash flows, and prospects, among other impacts:
Market, Financial and Economic Risks
•Our revenues, results of operations and operating cash flows are affected by price fluctuations in the wholesale power market and other market factors beyond our control.
•We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs or disruptions in these fuel markets may have an adverse impact on, our costs, revenues, results of operations, financial condition and cash flows.
•We have retired, announced planned retirements, and may be forced to retire or idle additional, underperforming generation units which could result in significant costs and have an adverse effect on our operating results.
•Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.
•Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows.
•Our results of operations and financial condition could be materially and adversely affected if energy market participants continue to construct new generation facilities or expand or enhance existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.
•The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions and limitations that could affect our ability to operate our business, our liquidity, and our results of operations, and any failure to comply with these restrictions could have a material adverse effect on us.
•We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy.
•Our solar generation, energy storage system, and other renewables development projects are subject to substantial uncertainties.
•Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or increased taxes or fees, could have a material adverse affect on our financial condition, results of operations and cash flows.
•We are required to pay the holders of TRA Rights for certain tax benefits, which amounts are expected to be substantial.
Regulatory and Legislative Risks
•Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and may in the future adversely impact, our businesses, results of operations, liquidity and financial condition.
•Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.
•Pending or proposed laws or regulations, including those proposed or implemented under the Biden administration, could have a material adverse effect on our businesses, results of operations, liquidity and financial condition.
•Changes to laws, rules or regulations related to market structures in the markets in which we participate may have a material adverse effect on our businesses, results of operation, liquidity and financial condition.
•We could be materially and adversely affected if current regulations are implemented or if new federal or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.
•Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.
•Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance of our retail businesses.
•Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers.
•The operation of our businesses is subject to cyber-based security and integrity risk. Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect on us.
•We may suffer material losses, costs and liabilities due to operational risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the Comanche Peak nuclear generation facility.
•The operation and maintenance of power generation facilities and related mining operations are capital intensive and involve significant risks that could adversely affect our results of operations, liquidity and financial condition.
•We may be materially and adversely affected by obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and monitoring relating to CCR.
•We are subject to, and may be materially and adversely affected by, the effects of extreme weather conditions and seasonality.
•The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, results of operations and cash flows.
•Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us.
Risks Related to Our Structure and Ownership of our Common Stock
•Investor focus on environmental, social, and governance issues, including climate change and sustainability matters, could adversely affect our stock price.
Please carefully consider the following discussion of significant factors, events, and uncertainties that make an investment in our securities risky. These factors, in addition to others specifically addressed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), provide important information for the understanding of our forward-looking statements in this annual report on Form 10-K. If one or more of the factors, events and uncertainties discussed below or in the MD&A were to materialize, our business, results of operations, liquidity, financial condition, cash flows, reputation or prospects could be materially adversely affected. In addition, if one or more of such factors, events and uncertainties were to materialize, it could cause results or outcomes to differ materially from those contained in or implied by any forward-looking statement in this annual report on Form 10-K. There may be further risks and uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our business, results of operations, liquidity, financial condition and prospects and the market price of our common stock in the future. The realization of any of these factors could cause investors in our securities (including our common stock) to lose all or a substantial portion of their investment.
Market, Financial and Economic Risks
Our revenues, results of operations and operating cash flows generally are affected by price fluctuations in the wholesale power market and other market factors beyond our control.
We are not guaranteed any rate of return on capital investments in our businesses. We conduct integrated power generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales of electricity and natural gas to end users and commodity risk management. Our wholesale and retail businesses are to some extent countercyclical in nature, particularly for the wholesale power and ancillary services supplied to the retail business. However, we do have a wholesale power position that is subject to wholesale power price moves, which may be significant. As a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices for electricity, natural gas, uranium, lignite, coal, fuel, and transportation in our regional markets and other competitive markets in which we operate and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities.
Market prices for power, capacity, ancillary services, natural gas, coal and fuel oil are unpredictable and may fluctuate substantially over relatively short periods of time. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Over-supply can occur as a result of the construction of new power generation sources, as we have observed in recent years. During periods of over-supply, electricity prices might be depressed. For example, the cost of electricity from renewable resources, such as solar, wind and battery storage systems, has dropped substantially in recent years. In many instances, energy from these sources are bid into the relevant spot market at a price of zero or close to zero during certain times of the day, lowering the clearing price for all power wholesalers in such market. Also, at times there is political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.
Extreme weather events can also materially impact power prices or otherwise exacerbate conditions or circumstances that result in volatility of power prices. For example, in February 2021, the U.S. experienced winter storm Uri and extreme cold temperatures in the central U.S., including Texas. This severe weather event substantially increased the demand for natural gas used in our electric power generation business, and the cold further limited the availability of renewable generation across the region contributing to extremely high market prices for natural gas and electricity, which resulted in substantial increases in the costs to procure sufficient fuel supply and increased collateral posting requirements. See "We may be materially and adversely affected by the effects of extreme weather conditions and seasonality" and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for additional discussion about the expected impacts of extreme weather, including the winter storm.
The majority of our facilities operate as "merchant" facilities without long-term power sales agreements. As a result, we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently, there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we are unable to hedge or otherwise secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.
We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs, volatility, or disruption in these fuel markets may have an adverse impact on our costs, revenues, results of operations, financial condition and cash flows.
We rely on natural gas, coal, fuel oil, and nuclear fuel for the majority of our power generation facilities. Delivery of these fuels to the facilities is dependent upon the continuing financial viability of contractual counterparties as well as upon the infrastructure (including mines, rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available and functioning to serve each generation facility. As a result, we are subject to the risks of disruptions or curtailments in the production of power at our generation facilities if no fuel is available at any price, if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
We have sold forward a substantial portion of our expected power sales in the next one to two years in order to lock in long-term prices. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) are volatile, and the wholesale price for electricity does not always change at the same rate as changes in fuel costs, and disruptions in our fuel supplies may therefore require us to find alternative fuel sources at costs which may be higher than planned, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Long-term and short-term contracts are subject to risk of non-delivery or claims of force majeure, which may impact our ability to economically recover the value of the contract. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting our obligations. Further, any changes in the costs of natural gas, coal, fuel oil, nuclear fuel or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, or if we are unable to procure these fuels at all, our financial condition, results of operations and cash flows could be materially adversely affected.
We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on our financial and operating performance. Volatility in market prices for fuel and electricity results from, among other factors:
•demand for energy commodities and general economic conditions;
•volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and fuel oil;
•volatility in market heat rates;
•volatility in coal and rail transportation prices;
•volatility in nuclear fuel and related enrichment and conversion services;
•disruption or other constraints or inefficiencies of electricity, natural gas or coal transmission or transportation;
•severe, sustained or unexpected weather conditions, including extreme cold, drought and limitations on access to water;
•changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
•illiquidity in the wholesale electricity or other commodity markets;
•transmission or transportation disruptions, constraints, inoperability or inefficiencies, or other changes in power transmission infrastructure;
•development and availability of new fuels, new technologies and new forms of competition for the production and storage of power, including competitively priced alternative energy sources or storage;
•changes in market structure and liquidity;
•changes in the way we operate our facilities, including curtailed operation due to market pricing, environmental regulations and legislation, safety or other factors;
•changes in generation capacity or efficiency;
•outages or otherwise reduced output from our generation facilities or those of our competitors;
•changes in electric capacity, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local subsidies, or additional transmission capacity;
•our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
•changes in the credit risk, payment practices, or financial condition of market participants;
•changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
•natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events; and
•changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and legislation.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for additional discussion about the expected impacts of winter storm Uri.
We have retired, announced planned retirements, and may be forced to retire or idle additional underperforming generation units which could result in significant costs and have an adverse effect on our operating results.
A sustained decrease in the financial results from, or the value of, our generation units has resulted in the retirement or planned retirement of, and ultimately could result in additional retirements or idling of, generation units. In recent years, we have generally operated certain of our lignite- and coal-fueled generation assets only during parts of the year that have higher electricity demand and, therefore, higher related wholesale electricity prices. In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required closure and reclamation, which could have a material adverse effect on our financial and operating performance.
Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.
Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative to the duration of available markets for various hedging activities. Generally, commodity markets that we participate in to hedge our exposure to electricity prices and heat rates have limited liquidity after two to three years. Further, our ability to hedge our revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally limited to a duration of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favorably or unfavorably.
To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Given our exposure to risks of commodity price movements, we devote a considerable amount of time and effort to the establishment of risk management policies and procedures, as well as the ongoing review of the implementation of these policies and procedures. Additionally, we have processes and controls in place that are designed to monitor and accurately report hedging activities and positions. The policies, procedures, processes and controls in place may not always function as planned and cannot eliminate all the risks associated with these activities, including unauthorized hedging activity, or improper reporting thereof, by our employees in violation of our existing risk management policies and procedures. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase electricity to meet unexpected demand in periods of high wholesale market prices or resell excess electricity into the wholesale market in periods of low prices. As a result of these and other factors, the impacts of our commodity hedging activities and risk management decisions may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Based on economic and other considerations, we may not be able to, or we may decide not to, hedge the entire exposure of our operations to commodity price risk. To the extent we do not hedge against commodity price risk and applicable commodity prices change in ways adverse to us, we could be materially and adversely affected. To the extent we do hedge against commodity price risk, those hedges may ultimately prove to be ineffective. Additionally, there may be changes to existing laws or regulations that could significantly impact our ability to effectively hedge, which may have a material adverse effect on us.
With the continued tightening of credit markets that began in 2008 and expansion of regulatory oversight through various financial reforms, there has been a decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity. Notably, participation by financial institutions and other intermediaries (including investment banks) in such markets has declined. Extended declines in market liquidity could adversely affect our ability to hedge our financial exposure to desired levels.
To the extent we engage in hedging and risk management activities, we are exposed to the credit risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations to us. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. Additionally, our counterparties may seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows. In such event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. Market participants in the ISOs/RTOs in which we operate are also exposed to risks that another market participant may default on its obligations to pay such ISO/RTO for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections available to such ISO/RTO, may be allocated to various non-defaulting ISO/RTO market participants, including us.
We do not apply hedge accounting to our commodity derivative transactions, which may cause increased volatility in our quarterly and annual financial results.
We engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the use of financial and physical derivative contracts for commodities. These derivatives are accounted for in accordance with GAAP, which requires that we record all derivatives on the balance sheet at fair value with changes in fair value immediately recognized in earnings as unrealized gains or losses. GAAP permits an entity to designate qualifying derivative contracts as normal purchases and sales. If designated, those contracts are not recorded at fair value. GAAP also permits an entity to designate qualifying derivative contracts in a hedge accounting relationship. If a hedge accounting relationship is used, a significant portion of the changes in fair value is not immediately recognized in earnings. We have elected not to apply hedge accounting to our commodity contracts, and we have designated contracts as normal purchases and sales in only limited cases, such as our retail sales contracts. As a result, our quarterly and annual financial results in accordance with GAAP are subject to significant fluctuations caused by changes in forward commodity prices.
Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows.
Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state entities, including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as out-of-market payments to new generators.
Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increases competition from these types of facilities and out-of-market subsidies to existing or new generation can undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by us.
We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources or experience in these areas. Over time, some of our plants may become unable to compete because of subsidized generation, including public utility commission supported power purchase agreements, and the construction of new plants. Such new plants could have a number of advantages including: more efficient equipment, newer technology that could result in fewer emissions or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities.
Other factors may contribute to increased competition in wholesale power markets. We expect that we will continue to face intense competition from numerous companies, including new entrants or consolidation of existing competitors, in the industry. Certain federal and state entities in jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants and attempt to incent, including through certain tax benefits, the construction and development of additional renewable resources as well as increases in energy efficiency investments. Subsidies (or increases thereto) to our competitors could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins that we can earn on the volumes we are able to serve. Further, with retail competition, it is easier for residential customers where we serve load to switch to and from competitive electricity generation suppliers for their energy needs. The volatility and uncertainty that results from such mobility may have material adverse effects on our financial condition, results of operations and cash flows. For example, if fewer customers switch to another supplier than anticipated, the load we must serve will be greater than anticipated and, if market prices of fuel have increased, our costs will increase more than expected due to the need to go to the market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we must serve will be lower than anticipated and, if market prices of electricity have decreased, our operating results could suffer.
Our results of operations and financial condition could be materially and adversely affected if energy market participants continue to construct new generation facilities or expand or enhance existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.
Given the overall attractiveness of certain of the markets in which we operate and certain tax benefits associated with renewable energy, among other matters, energy market participants have continued to construct new generation facilities or invest in enhancements or expansions of existing generation facilities despite relatively low wholesale power prices. If this market dynamic continues, our results of operations and financial condition could be materially and adversely affected if such additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power prices.
Economic downturns would likely have a material adverse effect on our businesses.
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including lower prices for power, generation capacity and natural gas, which can fluctuate substantially. Increased unemployment of residential customers and decreased demand for products and services by commercial and industrial customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer balances, which would negatively impact our overall sales and cash flows. Additionally, prolonged economic downturns that negatively impact our financial condition, results of operations and cash flows could result in future material impairment charges to write down the carrying value of certain assets to their respective fair values.
Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the future, which could have a material adverse effect on us. We currently maintain non-investment grade credit ratings that could negatively affect our ability to access capital on favorable terms or result in higher collateral requirements, particularly if our credit ratings were to be downgraded in the future.
Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs and collateral requirements, any of which could have a material adverse effect on us.
Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely impacted by, various factors, including:
•general economic and capital markets conditions, including changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on favorable terms or at all;
•conditions and economic weakness in the U.S. power markets;
•changes in interest rates;
•a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
•a downgrade of Vistra's or its applicable subsidiaries' credit ratings, or credit ratings of its issuances;
•our level of indebtedness and compliance with covenants in our debt agreements;
•a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the ability of such lender(s) to make loans to us;
•credit, security, or collateral requirements, including those relating to volatility in commodity prices;
•general credit availability from banks or other lenders for us and our industry peers;
•investor and lender confidence in and sentiment of the industry, our business, and the wholesale electricity markets in which we operate;
•a material breakdown in or oversight in effectuating our risk management procedures;
•the occurrence of changes in our businesses;
•disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities and energy storage systems; and
•changes in or the operation of provisions of tax and regulatory laws.
There are also increasing financial risks for companies that own and operate fossil fuel generation as institutional lenders have become more attentive to sustainable lending practices and some of them may elect not to provide funding for companies who produce or utilize fossil fuel energy or that have higher levels of GHG emissions. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists and others concerned about climate change not to provide funding for companies in the broader energy sector. Limitation on our access to, or increases in our cost of, capital could have a material adverse effect on us.
In addition, we currently maintain non-investment grade credit ratings. As a result, we may not be able to access capital on terms (financial or otherwise) as favorable as companies that maintain investment-grade credit ratings or we may be unable to access capital at all at times when the credit markets tighten. In addition, due to our non-investment grade credit ratings, counterparties request collateral support (including cash or letters of credit) in order to enter into certain transactions with us.
A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to shrink and could trigger liquidity demands pursuant to contractual arrangements. Future transactions by Vistra or any of its subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings.
Our indebtedness and the proposed phaseout of LIBOR, or the replacement of LIBOR with a different reference rate, could adversely affect our ability in the future to raise additional capital to fund our operations. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry, as well as impact our cash available for distribution.
As of December 31, 2020, we had approximately $9.6 billion of total indebtedness and approximately $9.2 billion of indebtedness net of cash. Our debt could have negative consequences for our financial condition including:
•increasing our vulnerability to general economic and industry conditions;
•requiring a significant portion of our cash flows from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to fund our operations, capital expenditures and future business opportunities;
•limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
•limiting our ability to fund operations or future acquisitions;
•restricting our ability to make distributions or pay dividends with respect to our capital stock and the ability of our subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;
•inhibiting the growth of our stock price;
•exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the Vistra Operations Credit Facilities, are at variable rates of interest;
•limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
•limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt.
We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In July 2017, the United Kingdom's Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. LIBOR is the interest rate benchmark used as a reference rate on a portion of our variable rate debt, including our revolving credit facility and interest rate swaps. It is unclear if LIBOR will cease to exist at that time or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. In November 2020, ICE Benchmark Administration (IBA), the administrator of LIBOR, with the support of the U.S. Federal Reserve and the United Kingdom's Financial Conduct Authority, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one-week and two-month USD LIBOR tenors, and on June 30, 2023 for all other USD LIBOR tenors. While this announcement extends the transition period to June 2023, the U.S. Federal Reserve concurrently issued a statement advising banks to stop new USD LIBOR issuances by the end of 2021. In light of these recent announcements, the future of LIBOR at this time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR's phaseout could cause LIBOR to perform differently than in the past or cease to exist. Although regulators and IBA have made clear that the recent announcements should not be read to say that LIBOR has ceased or will cease, in the event LIBOR does cease to exist, we may need to amend our credit agreements and other agreements with LIBOR as the referenced rate, which may result in interest rates and/or payments that do not correlate over time with the interest rates and/or payments that would have been made on our obligations if LIBOR was available in its current form. The Company will also need to consider new contracts and if they should reference an alternative benchmark rate or include suggested fallback language. Accordingly, we could be exposed to increased costs with respect to our variable rate debt, which could have an adverse impact on extensions of our credit and/or we might not be fully hedged on the variable rate exposure on our swapped indebtedness. Any such increased costs or exposure could increase our cost of capital and have a material adverse effect on us.
The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions and limitations that could affect our ability to operate our business, or liquidity, and results of operations, and any failure to comply with these restrictions could have a material adverse effect on us.
The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions that could adversely affect us by limiting our ability to operate our businesses and plan for, or react to, market conditions or to meet our capital needs and could result in an event of default under the Vistra Operations Credit Facilities and/or indentures. The Vistra Operations Credit Facilities and indentures contain events of default customary for financings of this type. If we fail to comply with the covenants in the Vistra Operations Credit Facilities and/or indentures and are unable to obtain a waiver or amendment, or a default exists and is continuing, the lenders under such agreements or notes, as the case may be, could give notice and declare outstanding borrowings thereunder immediately due and payable. The breach of any covenants or obligations in certain agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, not otherwise waived or amended, could result in a default under the applicable debt obligations and could trigger acceleration of those obligations, which in turn could trigger cross defaults under other agreements governing our debt, and any such acceleration of outstanding borrowings could have a material adverse effect on us.
Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs. If we are unable to provide such security, it may restrict our ability to conduct our business, which could have a material adverse effect on us.
We undertake certain hedging and commodity activities and enter into certain financing arrangements with various counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event we default on our obligations. We currently use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and the general perception of creditworthiness in the markets in which we operate. In the case of commodity arrangements, the amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral, we may not be able to manage price volatility effectively or to implement our strategy. An increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may have a material adverse effect on us.
We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy.
As part of our growth strategy, including our desire to grow our retail platform, we may pursue acquisitions of assets or operating entities. This strategy depends on the Company's ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on favorable terms. Our ability to continue to implement this component of our growth strategy will be limited by our ability to identify appropriate acquisition or joint venture candidates and our financial resources, including available cash and access to capital. In addition, the Company will compete with other companies for these limited acquisition opportunities, which may increase the Company's cost of making acquisitions or limit the Company’s ability to make acquisitions at all. Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to integrate an acquisition or our failure to integrate acquired businesses successfully could result in unanticipated expenses and losses. Furthermore, we may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures we may pursue. In addition, the process of integrating acquired operations into our existing operations may involve unknown risks, result in unforeseen operating difficulties and expenses, and may require significant financial resources that would otherwise be available for the execution of our business strategy. If the Company is unable to identify and consummate future acquisitions, it may impede the Company's ability to execute its growth strategy.
We have a substantial capital allocation plan intended for investments in renewable assets, including solar development projects and energy storage systems. As part of our business strategy, we plan to continually assess potential strategic acquisitions or investments in renewable assets, emerging technologies and related projects. Notably, the Company's ability to successfully develop our current renewables projects, or in the future acquire additional renewable assets, may be impacted by the demand for and viability of renewable assets generally, which may vary depending on availability of projects and financing, as well as public policy, financial and tax mechanisms implemented at the state and federal levels to support the development of renewable assets. Furthermore, various factors could result in increased costs or result in delays or cancellation of these projects, or the loss of, or declines in the value of, our investments in renewable projects. Risks may include both federal and state regulatory approval processes, new legislation impacting the industry, changes to federal income tax laws, economic events or factors, environmental and community concerns, availability of or requirements for additional funding, and enhanced competition. Should any of these factors occur, our financial position, results of operations, and cash flows could be adversely affected, or our future growth opportunities may not be realized as anticipated.
Our solar generation, energy storage system, and other renewables development projects are subject to substantial uncertainties.
Certain of our subsidiaries are in various stages of developing and constructing solar generation facilities and energy storage systems. Certain of these projects have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion of the development of these projects depends upon overcoming substantial risks, including, but not limited to, risks relating to siting, financing, engineering and construction, permitting, governmental approvals, regulatory changes, commissioning delays, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. Additionally, the increased demand for construction of renewables projects, such as energy storage systems and solar projects, may result in limited availability of qualified specialists, contractors, and necessary services and materials, which could lead to delays in and higher costs for the development and construction of our current and future planned projects.
In certain cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries have not yet secured power purchase arrangements or other important elements for a successful project. If the project does not proceed as planned, our subsidiaries may remain obligated for certain liabilities even though the project will not be completed. Development is inherently uncertain and we may forgo certain development opportunities and we may undertake significant development costs before determining that we will not proceed with a particular project. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance that any individual project will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development and write off the costs incurred in connection with such project and could incur additional losses associated with any related contingent liabilities.
Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.
In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets. Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an acceptable price and on acceptable terms and in a timely manner. In addition, a prospective buyer may have difficulty obtaining financing. Divestitures could involve additional risks, including:
•difficulties in the separation of operations and personnel;
•the need to provide significant ongoing post-closing transition support to a buyer;
•management's attention may be temporarily diverted;
•the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
•the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
•the disruption of our business; and
•potential loss of key employees.
We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset, which could adversely affect our results of operations and financial condition.
If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to earnings.
We have significant goodwill, intangible assets and long-lived assets recorded on our balance sheet. In accordance with U.S. GAAP, goodwill and non-amortizing intangible assets are required to be tested for impairment at least annually. Additionally, we review goodwill, our intangible assets and long-lived assets for impairment when events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline in future cash flows, slower growth rates in the energy industry, and a sustained decrease in the price of our common stock.
We performed our annual assessment of goodwill and non-amortizing intangibles in the fourth quarter of 2020 and determined that no impairment was required. However, impairment assessments will be performed in future periods and may result in an impairment loss, which could be material.
Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in an ownership change as defined in Internal Revenue Code (IRC) §382 could further limit our ability to use our federal net operating losses to offset our future taxable income.
If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs that could be used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382's broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is outside our control. Vistra acquired NOLs from its merger with Dynegy; however, Vistra's use of such attributes is limited under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy. If there is an "ownership change" with respect to Vistra (including by the normal trading activity of greater than 5% stockholders), the utilization of all NOLs existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382 that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change.
Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or increased taxes or fees, could have a material adverse effect on our financial condition, results of operations and cash flows.
We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. The Tax Cuts and Jobs Act of 2017 (TCJA), enacted December 22, 2017, introduced significant changes to current U.S. federal tax law. These changes are complex and continue to be the subject of additional guidance issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the federal tax changes by the individual states continues to evolve. Our interpretations and assumptions around U.S. tax reform may evolve in future periods as further administrative guidance and regulations are issued, which may materially affect our effective tax rate or tax payments.
U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations and financial condition.
Additionally, U.S. federal income tax reform and changes in other tax laws could adversely affect us. For example, President Biden has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to (i) an increase in the U.S. corporate income tax rate and (ii) implementation of a 15% minimum tax on a corporation’s worldwide book income. Congress could consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on various aspects of our operations. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees could have a material adverse effect on our financial condition, results of operations and cash flows.
We may be responsible for U.S. federal and state income tax liabilities that relate to the PrefCo Preferred Stock Sale and Spin-Off.
Pursuant to the Tax Matters Agreement, the parties thereto have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such covenant results in additional taxes to the other parties. If we breach such a covenant (or, in certain circumstances, if our stockholders or creditors of our Predecessor take or took certain actions that result in the intended tax treatment of the Spin-Off not to be preserved), we may be required to make substantial indemnification payments to the other parties to the Tax Matters Agreement.
The Tax Matters Agreement also allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off, (i) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (ii) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against certain taxes in the event the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.
Our indemnification obligations to EFH Corp. are not limited by any maximum amount. If we are required to indemnify EFH Corp. or such other persons under the circumstances set forth in the Tax Matters Agreement, we may be subject to substantial liabilities.
We are required to pay the holders of TRA Rights for certain tax benefits, which amounts could be substantial.
On the Effective Date, we entered into the TRA with American Stock Transfer & Trust Company, LLC, as the transfer agent. Pursuant to the TRA, we issued beneficial interests in the rights to receive payments under the TRA (TRA Rights) to the first lien creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive such TRA Rights under the Plan of Reorganization. Our financial statements reflect a liability of $450 million as of December 31, 2020 related to these future payment obligations (see Note 8 to the Financial Statements). This amount is based on certain assumptions as described more fully in the notes to the financial statements and the actual payments made under the TRA could be materially different than this estimate.
The TRA generally provides for the payment by us to the holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax that we and our subsidiaries actually realize as a result of our use of (a) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (b) the entire tax basis of the assets acquired as a result of the purchase and sale agreement, dated as of November 25, 2015 by and between La Frontera Ventures, LLC and Luminant, 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. The amount and timing of any payments under the TRA will vary depending upon a number of factors, including the amount and timing of the taxable income we generate in the future and the tax rate then applicable, our use of loss carryovers and the portion of our payments under the TRA constituting imputed interest.
Although we are not aware of any issue that would cause the IRS to challenge the tax benefits that are the subject of the TRA, recipients of the payments under the TRA will not be required to reimburse us for any payments previously made if such tax benefits are subsequently disallowed. As a result, in such circumstances, Vistra could make payments under the TRA that are greater than its actual cash tax savings. Any amount of excess payment can be used to reduce future TRA payments, but cannot be immediately recouped, which could adversely affect our liquidity.
Because Vistra is a holding company with no operations of its own, its ability to make payments under the TRA is dependent on the ability of its subsidiaries to make distributions to it. To the extent that Vistra is unable to make payments under the TRA because of the inability of its subsidiaries to make distributions to us for any reason, such payments will be deferred and will accrue interest until paid, which could adversely affect our results of operations and could also affect our liquidity in periods in which such payments are made.
The payments we will be required to make under the TRA could be substantial.
We may be required to make an early termination payment to the holders of TRA Rights under the TRA.
The TRA provides that, in the event that Vistra breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions.
As a result, upon any such breach or change of control, we could be required to make a lump sum payment under the TRA before we realize any actual cash tax savings and such lump sum payment could be greater than our future actual cash tax savings.
The aggregate amount of these accelerated payments could be materially more than our estimated liability for payments made under the TRA set forth in our financial statements, which could have a substantial negative impact on our liquidity.
We are potentially liable for U.S. income taxes of the entire EFH Corp. consolidated group for all taxable years in which we were a member of such group.
Prior to the Spin-Off, EFH Corporate Services Company, EFH Properties Company and certain other subsidiary corporations were included in the consolidated U.S. federal income tax group of which EFH Corp. was the common parent (EFH Corp. Consolidated Group). In addition, pursuant to the private letter ruling from the IRS that we received in connection with the Spin-Off, Vistra will be considered a member of the EFH Corp. Consolidated Group immediately prior to the Spin-Off. Under U.S. federal income tax laws, any corporation that is a member of a consolidated group at any time during a taxable year is severally liable for the group's entire federal income tax liability for the entire taxable year. In addition, entities that are disregarded for U.S. federal income tax purposes may be liable as successors under common law theories or under certain regulations to the extent corporations transferred assets to such entities or merged or otherwise consolidated into such entities, whether under state law or purely as a matter of federal income tax law. Thus, notwithstanding any contractual rights to be reimbursed or indemnified by EFH Corp. pursuant to the Tax Matters Agreement, to the extent EFH Corp. or other members of the EFH Corp. Consolidated Group fail to make any U.S. federal income tax payments required of them by law in respect of taxable years for which the Company or any subsidiary noted above was a member of the EFH Corp. Consolidated Group, the Company or such subsidiary may be liable for the shortfall. At such time, we may not have sufficient cash on hand to satisfy such payment obligation.
Our ability to claim a portion of depreciation deductions may be limited for a period of time.
Under the IRC, as amended, a corporation's ability to utilize certain tax attributes, including depreciation, may be limited following an ownership change if the corporation's overall asset tax basis exceeds the overall fair market value of its assets (after making certain adjustments). The Spin-Off resulted in an ownership change for the Company and it is expected that the overall tax basis of our assets may have exceeded the overall fair market value of our assets at such time. As a result, there may be a limitation on our ability to claim a portion of our depreciation deductions for a five-year period. This limitation could have a material impact on our tax liabilities and on our obligations under the TRA Rights. In addition, any future ownership change of Vistra following Emergence could likewise result in additional limitations on our ability to use certain tax attributes existing at the time of any such ownership change and have an impact on our tax liabilities and on our obligations under the TRA.
Regulatory and Legislative Risks
Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and may in the future adversely impact, our businesses, results of operations, liquidity, financial condition and cash flows.
Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity and natural gas. Although we attempt to comply with changing legislative and regulatory requirements, there is a risk that we will fail to adapt to any such changes successfully or on a timely basis. Compliance with, or changes to, the requirements under these legal and regulatory regimes, including those proposed or implemented under the Biden administration, may cause the Company may adversely impact our businesses, results of operations, liquidity, financial condition and cash flows.
Our businesses are subject to numerous state and federal laws (including, but not limited to, PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act (RCRA), the Energy Policy Act of 2005, the Dodd-Frank Wall Street Reform and the Consumer Protection Act and the Telephone Consumer Protection Act), changing governmental policy and regulatory actions (including those of the FERC, the NERC, the RCT, the MSHA, the EPA, the NRC, the DOJ, the FTC, the CFTC, state public utility commissions and state environmental regulatory agencies), and the rules, guidelines and protocols of ERCOT, CAISO, ISO-NE, MISO, NYISO and PJM with respect to various matters, including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, development, operation and reclamation of lignite mines, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition, administrative pricing mechanisms (and adjustments thereto), rates for wholesale sales of electricity, mandatory reliability standards and environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA. Additionally, Ambit’s direct selling business (i) could be found by federal, state or foreign regulators not to be in compliance with applicable law or regulations, which may lead to our inability to obtain or maintain a license, permit, or similar certification and (ii) may be required to alter its compensation practices in order to comply with applicable federal or state law or regulations. Changes in, revisions to, or reinterpretations of, existing laws and regulations may have a material adverse effect on our businesses, results of operations, liquidity, financial condition and cash flows.
As a result of the recent weather events in Texas there have been several announced efforts by both federal and state government and regulatory agencies to investigate and determine the causes of this event. We have received a civil investigative demand from the Attorney General of Texas as well as a request for information from ERCOT related to this event and may receive additional inquiries. We are cooperating with these entities and are working to respond to these requests. Those efforts may result in changes in regulations that impact our industry and businesses including, but not limited to, additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination among the various participants in the electricity supply chain during any future event; potential changes to the types of plans permitted to be marketed to residential customers; potential revisions to the way in which the ERCOT market compensates and incentivizes the continued operation of assets that only run periodically, including during this event or other times of scarcity; and other potential corrective actions that may be 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 and wholesale pricing of generation, or allocating the financial impacts of market-wide load shed ratably across all retail market participants). Recently announced or future legal proceedings, regulatory actions, investigations, or other administrative proceedings involving market participants may result lead to adverse determinations or other findings of violations of laws, rules or regulations, any of which may impact the ability of market participants to satisfy, in whole or in part, their respective obligations. We are continuing to monitor and evaluate the impacts of this developing situation but at this time we cannot estimate the likelihood or impacts of any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event on our business, financial condition, results of operations, or cash flows,. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the expected impacts of winter storm Uri.
Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation. For example, changes to, or development of, legislation that requires the use of clean renewable and alternate fuel sources or mandate the implementation of energy conservation programs that require the implementation of new technologies, could increase our capital expenditures and/or impact our financial condition. Additionally, in some retail energy markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-based pricing, re-regulate areas of these markets that have previously been competitive, or permit electricity delivery companies to construct or acquire generating facilities. Other proposals to re-regulate the retail energy industry may be made, and legislative or other actions affecting electricity and natural gas deregulation or restructuring process may be delayed, discontinued or reversed in states in which we currently operate or may in the future operate. If such changes were to be enacted by a regulatory body, we may lose customers, incur higher costs and/or find it more difficult to acquire new customers. These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business.
We are required to obtain, and to comply with, government permits and approvals.
We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental agencies. The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can sometimes result in the establishment of conditions that make the project or activity for which the permit or license was sought unprofitable or otherwise unattractive. In addition, such permits or licenses may be subject to denial, revocation or modification under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to comply with applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our delivery of electricity to our customers and may subject us to penalties and other sanctions. Although various regulators routinely renew existing permits and licenses, renewal of our existing permits or licenses could be denied or jeopardized by various factors, including (a) failure to provide adequate financial assurance for closure, (b) failure to comply with environmental, health and safety laws and regulations or permit conditions, (c) local community, political or other opposition and (d) executive, legislative or regulatory action.
Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such procurement or compliance, could have a material adverse effect on us. In addition, new environmental legislation or regulations, if enacted, or changed interpretations of existing laws, may cause activities at our facilities to need to be changed to avoid violating applicable laws and regulations or elicit claims that historical activities at our facilities violated applicable laws and regulations. In addition to the possible imposition of fines in the case of any such violations, we may be required to undertake significant capital investments and obtain additional operating permits or licenses, which could have a material adverse effect on us.
Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.
We are subject to extensive environmental regulation by governmental authorities, including federal and state environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could be subject to administrative, civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements. Any of the foregoing could have a material adverse effect on us.
The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. In the future, the EPA may also propose and finalize additional regulatory actions that may adversely affect our existing generation facilities or our ability to cost-effectively develop new generation facilities. There is no assurance that the currently installed emissions control equipment at our lignite, coal and/or natural gas-fueled generation facilities will satisfy the requirements under any future EPA or state environmental regulations. Some of the recent regulatory actions, such as the EPA's proposed Cross-State Air Pollution Rule Update, the ACE rule and any proposed or future actions to replace the ACE rule, and actions under the Regional Haze program, could require us to install significant additional control equipment, resulting in potentially material costs of compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production curtailments. These costs could have a material adverse effect on us.
We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped, disrupted, curtailed or modified or become subject to additional costs. Any such stoppage, disruption, curtailment, modification or additional costs could have a material adverse effect on us.
In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased, developed or sold, regardless of when the liabilities arose and whether they are now known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us, which could have a material adverse effect on us.
We could be materially and adversely affected if new federal or state legislation or regulations are adopted to address global climate change that could require efforts that exceed or are more expensive than our currently planned initiatives or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.
There is attention and interest nationally and internationally about global climate change and how GHG emissions, such as CO2, contribute to global climate change. Over the last several years, the U.S. Congress has considered and debated several proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards. In July 2019, the EPA finalized the ACE rule that developed emissions guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. In January 2021, the ACE rule was vacated by the D.C. Circuit Court and remanded to the EPA for further consideration in accordance with the court’s ruling. The EPA may develop a more stringent and more encompassing rule to replace the ACE rule in its remand proceeding and has been directed by the Biden Administration to review this rule and others promulgated by the EPA during the Trump Administration. Prior to the vacatur and remand, states where we operate coal plants (Texas, Illinois and Ohio) had begun the development of their state plans to comply with the now-vacated ACE rule. In January 2021, the ACE rule was invalidated by the D.C. Circuit Court. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions. We could be materially and adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change that could require efforts that exceed or are more expensive than our currently planned initiatives or if we are subject to lawsuits for alleged damage to persons or property resulting from GHG emissions.
Additionally, in January 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to rejoin the Paris Agreement, effective in February 2021. Although the Paris Agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions, and various corporations, investors and U.S. states and local governments have previously pledged to further the goals of the Paris Agreement. Additionally, the Biden Administration has directed certain agencies to submit a plan to the National Climate Task Force to achieve a carbon-pollution-free electricity sector by 2035. The Company's plan to transition to clean power generation sources and reduce its GHG emissions may not be completed in this timeframe and we may not otherwise achieve our sustainability and emissions reduction targets as expected. Accordingly, we may be required to accelerate or change our targets, incur additional expenses, and/or adjust or cease certain operations as a result of newly implemented federal and/or state regulations to reduce future carbon emissions.
The Capacity Performance product in the PJM market and the Pay-for-Performance mechanism in ISO-NE could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. We may experience substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Luminant's mining operations are subject to RCT oversight.
We currently own and operate, or are in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. We also own or lease, and are in the process of reclaiming, two waste-to-energy surface facilities in Pennsylvania. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all the requirements of its mining permits. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities.
Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations are reclaimed over the next several years.
In conjunction with Luminant's announcements in 2017 to retire several power generation assets and related mining operations, along with the continuous reclamation activity at its continuing mining operations for its mines related to the Oak Grove and Martin Lake generation assets, Luminant is expected to spend a significant amount of money, internal resources and time to complete the required reclamation activities. For the next five years, Vistra is projected to spend approximately $301 million (on a nominal basis) to achieve its reclamation objectives.
Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.
We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment, commercial, and environmental issues, and other claims for injuries and damages. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk.
We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a materially adverse effect on us.
Our retail businesses, which each have REP certifications that are subject to review of the public utility commissions in the states in which we operate, are subject to changing state rules and regulations that could have a material impact on the profitability of our business.
The competitiveness of our U.S. retail businesses partially depends on state regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers. Specifically, the public utility commissions and/or the attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an investigation into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements. These state policies and investigations, which can include controls on the retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on our ability to obtain new customers through various marketing channels and disclosure requirements, investigations into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements, can affect the competitiveness of our retail businesses. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers in the applicable jurisdiction, and such decertification could have a material adverse effect on us. Additionally, state or federal imposition of net metering or renewable portfolio standard programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power. Our retail businesses have limited ability to influence development of these state rules, regulations and policies, and our business model may be more or less effective, depending on changes to the regulatory environment.
Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance of our retail businesses.
Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail businesses purchase a portion of their supply requirements from third parties. As a result, the financial performance of our retail business depends on their ability to obtain adequate supplies of electric generation from third parties at prices below the prices they charge their customers. Consequently, our earnings and cash flows could be adversely affected in any period in which the retail businesses' wholesale electricity supply costs rise at a greater rate than the rates they charge to customers. The price of wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:
•varying supply procurement contracts used and the timing of entering into related contracts;
•subsequent changes in the overall price of natural gas;
•daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
•transmission constraints and the Company's ability to move power to our customers;
•out-of-market payments, uplifts, or other non-pass through charges, and
•changes in market heat rate.
The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers' actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, competition and economic conditions. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the expected impacts of winter storm Uri.
Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers.
We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for customers. We believe our brands are viewed favorably in the retail electricity markets in which we operate, but despite our commitment to providing superior customer service and innovative products, customer sentiment toward our brands, including by comparison to our competitors' brands, depends on certain factors beyond our control. For example, competitor REPs may offer different products, lower electricity prices and other incentives, which, despite our long-standing relationship with many customers, may attract customers away from us. If we are unable to successfully compete with competitors in the retail market it is possible our retail customer counts could decline, which could have a material adverse effect on us.
As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may have certain advantages over us. For example, in new markets, our principal competitor for new customers may be the incumbent REP, which has the advantage of long-standing relationships with its customers, including well-known brand recognition. In addition to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger than we are or have greater resources or access to capital than we have. If there is inadequate potential margin in retail electricity markets with substantial competition to overcome the adverse effect of relatively high customer acquisition costs in such markets, it may not be profitable for us to compete in these markets.
Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material adverse effect on us.
The substantial majority of our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area or, with respect to capacity performance in PJM and performance incentives in ISO-NE, we may be subject to significant penalties. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service. Any of the foregoing could have a material adverse effect on us.
The operation of our businesses is subject to cyber-based security and integrity risk. Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect on us.
Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems and much of our information technology infrastructure is connected (directly or indirectly) to the internet. Our information technology systems and infrastructure, and those of our vendors and suppliers, are susceptible to damage, disruptions, or shutdowns due to power outages, hardware failures, programming errors, defects or other vulnerabilities, cyber-attacks, ransomware attacks, malware attacks, computer viruses, theft, misconduct by employees or other insiders, telecommunications failures, misuse, human errors or other catastrophic events. While we have controls in place designed to protect our infrastructure, such breaches and threats are becoming increasingly sophisticated, complex, change frequently and may be difficult to detect. Any such breach, disruption or similar event that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties, which could have a material adverse effect on us.
As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber/data and physical security breaches.
Further, our retail business requires us to access, collect, store and transmit sensitive customer data in the ordinary course of business. Concerns about data privacy have led to increased regulation and other actions that could impact our businesses. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers' license numbers, social security numbers and bank account information. Our retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. Although we take precautions to protect the sensitive customer data that we are required to collect in order to conduct our business, if a significant breach of our information technology systems were to occur, the reputation of our retail business may be adversely affected, customer confidence may be diminished, and our retail business may be subject to substantial legal or regulatory claims, any of which may contribute to the loss of customers and have a material adverse effect on us. Any loss of customer, confidential, or proprietary data through a breach, unauthorized access, disruption, misuse or disclosure could adversely affect our reputation, expose us to material legal or regulatory claims and impair our ability to execute our business strategy, which could have a material adverse effect on us. In addition, we may experience increased capital and operating costs to implement increased security for our information technology infrastructure. We cannot provide any assurance that such events and impacts will not be material in the future, and our efforts to deter, identify and mitigate future breaches may require additional significant capital and may not be successful.
We may suffer material losses, costs and liabilities due to operation risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the Comanche Peak nuclear generation facility.
We own and operate a nuclear generation facility in Glen Rose, Texas (Comanche Peak Facility). The ownership and operation of a nuclear generation facility involves certain risks. These risks include:
•unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity or other problems;
•inadequacy or lapses in maintenance protocols;
•the impairment of reactor operation and safety systems due to human error or force majeure;
•the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;
•the costs of procuring nuclear fuel;
•the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
•terrorist or cybersecurity attacks and the cost to protect against any such attack;
•the impact of a natural disaster;
•limitations on the amounts and types of insurance coverage commercially available; and
•uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives.
Any prolonged unavailability of the Comanche Peak Facility could have a material adverse effect on our results of operation, cash flows, financial position and reputation. The following are among the more significant related risks:
•Operational Risk — Operations at any generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur at the Comanche Peak Facility, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at the Comanche Peak Facility.
•Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, as to which no assurance can be given, the NRC operating licenses for the two licensed operating units at the Comanche Peak Facility will expire in 2030 and 2033, respectively. Changes in regulations by the NRC, as well as any extension of our operating licenses, could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
•Nuclear Accident Risk — Although the safety record of the Comanche Peak Facility and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the Comanche Peak Facility.
The operation and maintenance of power generation facilities and related mining operations are capital intensive and involve significant risks that could adversely affect our results of operations, liquidity and financial condition.
The operation and maintenance of power generation facilities and related mining operations involve many risks, including, as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source, the inability to transport our product to our customers in an efficient manner due to the lack of transmission capacity or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in substantial lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. Older generating equipment, even if maintained or refurbished in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (b) any unexpected failure to generate power, including failure caused by equipment breakdown or unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of weather events or natural disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cyber/data security acts and other catastrophic events and (d) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete routine maintenance or other capital projects at our existing facilities is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs or losses and write downs of our investment in the project.
We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist or cyber/data security attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on us. Moreover, if we significantly modify a unit, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the CAA, which would likely result in substantial additional capital expenditures.
In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise, typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or non-performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to procure replacement power at spot market prices in order to fulfill contractual commitments. If we do not have adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on us. Further, our inability to operate our generation facilities efficiently, manage capital expenditures and costs, and generate earnings and cash flows from our asset-based businesses could have a material adverse effect on our results of operations, financial condition or cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance by contractors or vendors.
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our revenues and results of operations, and we may not have adequate insurance to cover these risks and hazards. Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as extreme weather, earthquake, flood, lightning, hurricane and wind, other human-made hazards, such as nuclear accidents, dam failure, gas or other explosions, mine area collapses, fire, structural collapse, machinery failure and other dangerous incidents are inherent risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. Further, our employees and contractors work in, and customers and the general public may be exposed to, potentially dangerous environments at or near our operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life.
The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject and, even if we do have insurance coverage for a particular circumstance, we may be subject to a large deductible and maximum cap. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, including increasing pressure on firms that provide insurance to companies that own and operate fossil fuel generation, we cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
We may be materially and adversely affected by obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and monitoring relating to CCR.
As a result of electricity produced for decades at coal-fueled power plants in Illinois, Texas and Ohio, we manage large amounts of CCR material in surface impoundments, all in compliance with applicable regulatory requirements. In addition to the federal requirements under the CCR rule, CCR surface impoundments will continue to be regulated by existing state laws, regulations and permits, as well as additional legal requirements that may be imposed in the future. These federal and state laws, regulations and other legal requirements may require or result in additional expenditures, increased operating and maintenance costs and/or result in closure of certain power generating facilities, which could affect the results of operations, financial position and cash flows of the Company. We have recognized ARO related to these CCR-related requirements. As the closure and CCR management work progresses and final closure plans and corrective action measures are developed and approved at each site, the scope and complexity of work and the amount of CCR material could be greater than current estimates and could, therefore, materially impact earnings through increased compliance expenditures.
The EPA is reviewing applications submitted by us to extend closure deadlines for many of our CCR impoundments. The EPA has been directed by the Biden Administration to review a number of environmental rules adopted by the EPA during the Trump Administration, including Coal Combustion Residuals (CCR) rule, the Emissions Limitation Guidelines (ELG) rule, the Affordable Clean Energy (ACE) rule and the PM and Ozone National Ambient Air Quality Standards (NAAQS) rules. All of these rules may significantly and adversely impact our existing coal fleet and may lead to accelerated plant closure timeframes. In addition, the expected revisions to the ACE rule and NAAQS also have the potential to adversely impact our gas-fired units.
The EPA is reviewing applications submitted by us to extend closure deadlines for many of our CCR impoundments. The scope and cost of that closure work could increase significantly based on new requirements imposed by the EPA or state agencies. There is no assurance that our current assumptions for closure activities will be accepted by EPA. If ponds must be closed sooner than anticipated, plant closures timeframes may be accelerated.
The availability and cost of emission allowances could adversely impact our costs of operations.
We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2, CO2 and NOX to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
We may be materially and adversely affected by the effects of extreme weather conditions and seasonality.
We may be materially affected by weather conditions and our businesses may fluctuate substantially on a seasonal basis as the weather changes. In addition, we are subject to the effects of extreme weather conditions, including sustained or extreme cold or hot temperatures, hurricanes, floods, storms, fires, earthquakes or other natural disasters, which could stress our generation facilities and grid reliability, limit our ability to procure adequate fuel supply, or result in outages, damage or destroy our assets and result in casualty losses that are not ultimately offset by insurance proceeds, and could require increased capital expenditures or maintenance costs, including supply chain costs.
Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, certain extreme weather events have previously affected, and may in the future, affect, the availability of generation and transmission capacity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants, including due to damage to rail or natural gas pipeline infrastructure. Additionally, extreme weather has resulted, and may in the future result, in (i) unexpected increases in customer load, requiring our retail operation to procure additional electricity supplies at wholesale prices in excess of customer sales prices for electricity, (ii) the failure of equipment at our generation facilities, (iii) a decrease in the availability of, or increases in the cost of, fuel sources, including natural gas, diesel and coal, or (iv) unpredictable curtailment of customer load by the applicable ISO/RTO in order to maintain grid reliability, resulting in the realization of lower wholesale prices or retail customer sales. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the expected impacts of winter storm Uri.
Additionally, climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects.
Weather conditions, which cannot be reliably predicted, could have adverse consequences by requiring us to seek additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low, as well as significantly limiting the supply of, or increasing the cost of our fuel supply, each of which could have a material adverse effect on our business, results of operations, financial condition and liquidity.
The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, and results of operations.
The outbreak of the COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, and we are responding to the outbreak by taking steps to mitigate the potential risks to us posed by its spread. We continue to examine the impacts of the pandemic on our workforce, liquidity, reliability, cybersecurity, customers, suppliers, along with other macroeconomic conditions and cannot currently predict whether COVID-19 will have a material impact on our results of operations, financial condition, and cash flows.
Because we are deemed a critical infrastructure provider that provides a critical service to our customers, we must keep our employees who operate our businesses safe and minimize unnecessary risk of exposure. We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic. This plan guides our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we will take additional precautions that we determine are necessary in order to mitigate the impacts. In particular, we have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities including requiring, for both employees and contractors, social distancing where possible and requiring the use of appropriate personal protective equipment in certain circumstances. We have implemented work-from-home policies and other safety measures where appropriate, including, but not limited to, temperature testing at all of our locations for employees, contractors, and other essential visitors and closing our facilities to non-essential visitors. While our systems and operations remain vulnerable to cyber-attacks and other disruptions due in part to the fact that a portion of our workforce continues to work remotely, we have implemented physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. We will continue to review and modify our plans as conditions change.
Measures to control the spread of COVID-19, including restrictions on travel, public gatherings, and certain business operations, have affected the demand for the products and services of many businesses in the areas in which we operate and disrupted supply chains around the world. The full scope and extent of the impacts of COVID-19 on our operations are unknown at this time. However, COVID-19 or another pandemic could have material and adverse effects on our results of operations, financial condition and cash flows due to, among other factors, a protracted slowdown of broad sectors of the economy, changes in demand or supply for commodities, significant changes in legislation or regulatory policy to address the pandemic (including moratoriums or conditions or disconnections and limits or restrictions or late fees), reduced demand for electricity (particularly from commercial and industrial customers), increased late or uncollectible customer payments, negative impacts on the health of our workforce, a deterioration of our ability to ensure business continuity (including increased risk from cybersecurity attacks as a result of a significant portion of our workforce continuing to work from home), and the inability of the Company's contractors, suppliers, and other business partners to fulfill their contractual obligations.
Despite our efforts to manage these impacts to the Company, their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. To the extent COVID-19 adversely affects our business and financial results, it may also have the effect of hastening, heightening, or increasing the negative impacts of, many of the other risks described in this Risk Factors section.
Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us.
Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to produce and store power, including gas turbines, wind turbines, fuel cells, hydrogen, micro turbines, photovoltaic (solar) cells, batteries and concentrated solar thermal devices, along with improvements in traditional technologies. Such technological advances may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, and have resulted, and are expected to continue to reduce the costs of power production or storage, which may result in the obsolescence of certain of our operating assets. Consequently, the value of our more traditional generation assets could be significantly reduced as a result of these competitive advances, which could have a material adverse effect on us and our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services and products that meet customer demands and evolving industry standards. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers buy electricity (i.e., self-generation or distributed-generation facilities). To the extent self-generation or distributed generation facilities become a more cost-effective option for customers, our financial condition, operating cash flows and results of operations could be materially and adversely affected.
Technological advances in demand-side management and increased conservation efforts have resulted, and are expected to continue to result, in a decrease in electricity demand. A significant decrease in electricity demand as a result of such efforts would significantly reduce the value of our generation assets. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce power consumption. Effective power conservation by our customers could result in reduced electricity demand or significantly slow the growth in such demand. Any such reduction in demand could have a material adverse effect on us. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures. Additionally, increased governmental and consumer focus on energy sustainability efforts, including desire for, or incentives related to, the development, implementation and usage of low-carbon technology, may result in decreased demand for the traditional generation technologies that we currently own and operate.
We may potentially be affected by emerging technologies that may over time affect change in capacity markets and the energy industry overall with the inclusion of distributed generation and clean technology.
Some of these emerging technologies are shale gas production, distributed renewable energy technologies, energy efficiency, broad consumer adoption of electric vehicles, distributed generation and energy storage devices. Such emerging technologies could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. These emerging technologies may also affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on our financial condition, results of operations and cash flows could be materially adversely affected.
The loss of the services of our key management and personnel could adversely affect our ability to successfully operate our businesses.
Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside of our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract highly qualified new personnel or retain highly qualified existing personnel could have an adverse effect on our ability to successfully operate our businesses. In addition, effective succession planning is important to our long-term success. Failure to timely and effectively ensure transfer of knowledge and smooth transitions involving senior management and other key personnel could hinder our strategic planning and execution.
We could be materially and adversely impacted by strikes or work stoppages by our unionized employees.
As of December 31, 2020, we had approximately 1,640 employees covered by collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal- and nuclear-fueled generation operation and some of our natural gas-fueled generation operations expire on various dates between May 2021 and November 2023, but remain effective thereafter unless and until terminated by either party. We are also presently negotiating the terms of first contracts at two of our natural gas-fueled generation facilities. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. Our ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate current or future collective bargaining agreements on favorable terms or at all could have a material adverse effect on us.
Risks Related to Our Structure and Ownership of our Common Stock
Vistra is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities of its subsidiaries.
Vistra is a holding company that does not conduct any business operations of its own. As a result, Vistra's cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra's subsidiaries and the payment of such operating cash flows to Vistra in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from Vistra and have no obligation (other than any existing contractual obligations) to provide Vistra with funds to satisfy its obligations. Any decision by a subsidiary to provide Vistra with funds to satisfy its obligations, including those under the TRA, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary's results of operations, financial condition, cash flows, cash requirements, contractual prohibitions and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to Vistra.
Investor focus on environmental, social, and governance issues, including climate change and sustainability matters, could adversely affect our stock price.
Investor focus on environmental, social, and governance issues, including increasing attention on climate change and sustainability matters, could adversely affect, and increase the potential volatility of, our stock price. Certain financial institutions have announced policies to presently or in the future cease investing or to divest investments in companies that derive any or a specified portion of their income from, or have any or a specified portion of their operations in, fossil fuels. To date these represent small fractions of our overall current or potential equity investors, but that group could grow and thus reduce demand for our common stock or otherwise increase volatility in our stock price. The Company’s plan to transition to clean power generation sources and reduce its carbon footprint may not be completed in the timeframe or achieve the targets as expected. Negative investor sentiment toward us and our industry — including concerns over environmental or sustainability matters and potential changes in federal and state regulatory actions related thereto — could have a negative impact on our stock price.
We may not pay any dividends on our common stock in the future.
In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, our results of operations, financial condition and liquidity, contractual prohibitions and other restrictions with respect to the payment of dividends. There is no assurance that the Board will declare, or that we will pay, any dividends on our common stock in the future.
Item 1B.UNRESOLVED STAFF COMMENTS
Luminant's asset fleet consists of power generation and battery ESS units in six ISOs/RTOs, with the location, ISO/RTO, technology, primary fuel type, net capacity and ownership interest for each generation facility shown in the table below:
|Facility||Location||ISO/RTO||Technology||Primary Fuel (a)||Net Capacity (MW) (b)||Ownership Interest (c)|
|Ennis||Ennis, TX||ERCOT||CCGT||Natural Gas||366||100%|
|Forney||Forney, TX||ERCOT||CCGT||Natural Gas||1,912||100%|
|Hays||San Marcos, TX||ERCOT||CCGT||Natural Gas||1,047||100%|
|Lamar||Paris, TX||ERCOT||CCGT||Natural Gas||1,076||100%|
|Midlothian||Midlothian, TX||ERCOT||CCGT||Natural Gas||1,596||100%|
|Odessa||Odessa, TX||ERCOT||CCGT||Natural Gas||1,054||100%|
|Wise||Poolville, TX||ERCOT||CCGT||Natural Gas||787||100%|
|Martin Lake||Tatum, TX||ERCOT||ST||Coal||2,250||100%|
|Oak Grove||Franklin, TX||ERCOT||ST||Coal||1,600||100%|
|DeCordova||Granbury, TX||ERCOT||CT||Natural Gas||260||100%|
|Graham||Graham, TX||ERCOT||ST||Natural Gas||630||100%|
|Lake Hubbard||Dallas, TX||ERCOT||ST||Natural Gas||921||100%|
|Morgan Creek||Colorado City, TX||ERCOT||CT||Natural Gas||390||100%|
|Permian Basin||Monahans, TX||ERCOT||CT||Natural Gas||325||100%|
|Stryker Creek||Rusk, TX||ERCOT||ST||Natural Gas||685||100%|
|Trinidad||Trinidad, TX||ERCOT||ST||Natural Gas||244||100%|
|Comanche Peak||Glen Rose, TX||ERCOT||Nuclear||Nuclear||2,300||100%|
|Upton 2||Upton County, TX||ERCOT||Solar/Battery||Renewable||180||100%|
|Total Texas Segment||17,623|
|Fayette||Masontown, PA||PJM||CCGT||Natural Gas||726||100%|
|Hanging Rock||Ironton, OH||PJM||CCGT||Natural Gas||1,430||100%|
|Hopewell||Hopewell, VA||PJM||CCGT||Natural Gas||370||100%|
|Kendall||Minooka, IL||PJM||CCGT||Natural Gas||1,288||100%|
|Liberty||Eddystone, PA||PJM||CCGT||Natural Gas||607||100%|
|Ontelaunee||Reading, PA||PJM||CCGT||Natural Gas||600||100%|
|Sayreville||Sayreville, NJ||PJM||CCGT||Natural Gas||349||100%|
|Washington||Beverly, OH||PJM||CCGT||Natural Gas||711||100%|
|Calumet||Chicago, IL||PJM||CT||Natural Gas||380||100%|
|Dicks Creek||Monroe, OH||PJM||CT||Natural Gas||155||100%|
|Miami Fort (CT)||North Bend, OH||PJM||CT||Fuel Oil||77||100%|
|Pleasants||Saint Marys, WV||PJM||CT||Natural Gas||388||100%|
|Richland||Defiance, OH||PJM||CT||Natural Gas||423||100%|
|Facility||Location||ISO/RTO||Technology||Primary Fuel (a)||Net Capacity (MW) (b)||Ownership Interest (c)|
|Stryker||Stryker, OH||PJM||CT||Fuel Oil||16||100%|
|Bellingham||Bellingham, MA||ISO-NE||CCGT||Natural Gas||566||100%|
|Blackstone||Blackstone, MA||ISO-NE||CCGT||Natural Gas||544||100%|
|Casco Bay||Veazie, ME||ISO-NE||CCGT||Natural Gas||543||100%|
|Lake Road||Dayville, CT||ISO-NE||CCGT||Natural Gas||827||100%|
|Masspower||Indian Orchard, MA||ISO-NE||CCGT||Natural Gas||281||100%|
|Milford||Milford, CT||ISO-NE||CCGT||Natural Gas||600||100%|
|Independence||Oswego, NY||NYISO||CCGT||Natural Gas||1,212||100%|
|Total East Segment||12,093|
|Moss Landing 1 & 2||Moss Landing, CA||CAISO||CCGT||Natural Gas||1,020||100%|
|Moss Landing||Moss Landing, CA||CAISO||Battery||Renewable||300||100%|
|Oakland||Oakland, CA||CAISO||CT||Fuel Oil||165||100%|
|Total West Segment||1,485|
|Coleto Creek||Goliad, TX||ERCOT||ST||Coal||650||100%|
|Joppa CT 1-3||Joppa, IL||MISO||CT||Natural Gas||165||100%|
|Joppa CT 4-5||Joppa, IL||MISO||CT||Natural Gas||56||80%|
|Miami Fort 7 & 8||North Bend, OH||PJM||ST||Coal||1,020||100%|
|Total Sunset Segment||7,486|
(a)Renewable represents generation assets fueled by renewable sources including energy storage and solar, which do not have significant fuel costs.
(b)Unit capabilities are based on winter capacity and are reflected at our net ownership interest. We have not included units that have been retired or are out of operation.
(c)Ownership interest of 100% indicates fee simple ownership of the facility. Ownership of less than 100% indicates the share of ownership in the facility held by the Company.
See Note 3 to the Financial Statements for discussion of our solar and battery energy storage projects currently under development.
Our wholesale commodity risk management group also procures renewable energy credits from renewable generation in ERCOT to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewable resources from such customers. As of December 31, 2020, Vistra had long-term power purchase agreements to procure approximately 1,015 MW of available renewable capacity. These renewable generation sources deliver electricity when conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be relied upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their output.
Nuclear — We own and operate two nuclear generation units at the Comanche Peak plant site in ERCOT, each of which is designed for a capacity of 1,150 MW. Comanche Peak Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which occurred in 2020. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. The Comanche Peak facility operated at a capacity factor of 97%, 96% and 101% in 2020, 2019 and 2018, respectively.
We have contracts in place for all of our 2021 and the majority of our 2022 nuclear fuel requirements. We do not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion, enrichment and fabrication services in the foreseeable future.
Natural Gas — Our natural gas-fueled generation fleet is comprised of 23 CCGT generating facilities totaling 19,512 MW and 13 peaking generation facilities totaling 5,022 MW. We satisfy our fuel requirements at these facilities through a combination of spot market and near-term purchase contracts. Additionally, we have near-term natural gas transportation agreements in place to ensure reliable fuel supply.
Coal/Lignite — Our coal/lignite-fueled generation fleet is comprised of 10 generation facilities totaling 11,115 MW of generation capacity. Maintenance outages at these units are scheduled during the spring or fall off-peak demand periods. We meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from multiple suppliers under contracts of various lengths and transported to the facilities by either railcar or barges. We meet our fuel requirements in ERCOT using lignite that we mine at the Oak Grove generation facility, coal purchased and transported by railcar at the Coleto Creek generation facility and a blend of lignite that we mine and coal purchased and transported by railcar at our Martin Lake generation facility.
Item 3.LEGAL PROCEEDINGS
See Note 13 to the Financial Statements for discussion of litigation, including matters related to our generation facilities and EPA reviews.
Item 4.MINE SAFETY DISCLOSURES
Vistra currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel for its electricity generation facilities. Vistra also owns or leases, and is in the process of reclaiming, two waste-to-energy surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra's mines, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95.1 to this annual report on Form 10-K.
Item 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Vistra's authorized capital stock consists of 1,800,000,000 shares of common stock with a par value of $0.01 per share.
Since May 10, 2017, Vistra's common stock has been listed on the NYSE under the symbol "VST".
On April 9, 2018 (Merger Date), pursuant to the Merger Agreement, 94,409,573 shares of Vistra common stock were issued to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units and warrants.
As of February 23, 2021, there were 483,716,012 shares of common stock issued and outstanding and 698 stockholders of record.
In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. Our common stockholders are entitled to receive any such dividends or other distributions ratably. In February 2021, our Board declared a quarterly dividend of $0.15 per share that will be paid in March 2021. 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, our results of operations, financial condition and liquidity, Delaware law and contractual limitations. For additional details, see Item 1A. Risk Factors and Note 14 to the Financial Statements
Stock Performance Graph
The performance graph below compares Vistra's cumulative total return on common stock for the period from May 10, 2017 (the date we were listed on the NYSE) through December 31, 2020 with the cumulative total returns of the S&P 500 Stock Index (S&P 500) and the S&P Utility Index (S&P Utilities). The graph below compares the return in each period assuming that $100 was invested at May 10, 2017 in Vistra's common stock, the S&P 500 and the S&P Utilities, and that all dividends were reinvested.
Share Repurchase Program
The following table provides information about our repurchase of equity securities that are registered by us pursuant to Section 12 of the Exchange Act, as amended, during the quarter ended December 31, 2020.
|Total Number of Shares Purchased||Average Price Paid per Share||Total Number of Shares Purchased as Part of a Publicly Announced Program||Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)|
|October 1 - October 31, 2020||—||$||—||—||$||332|
|November 1 - November 30, 2020||—||$||—||—||$||332|
|December 1 - December 31, 2020||—||$||—||—||$||332|
|For the quarter ended December 31, 2020||—||$||—||—||$||332|
In September 2020, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $1.5 billion of our outstanding common stock may be repurchased. The Share Repurchase Program became effective January 1, 2021, at which time the Prior Share Repurchase Plan (described below) and all authorized amounts remaining thereunder terminated as of such date.
Under the Share Repurchase Program, any purchases of shares of the Company's stock may be repurchased from time to time 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 June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding common stock could be purchased, and in November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our outstanding stock could be purchased, resulting in an aggregate $1.750 billion share repurchase program (Prior Share Repurchase Program). The Prior Share Repurchase Program terminated effective January 1, 2021.
See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program and the Prior Share Repurchase Program.
Item 6.SELECTED FINANCIAL DATA
Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion below, as well as other portions of this annual report on Form 10-K, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as “may,” “will,” “should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part I, Item 1A "Risk Factors" and other risks discussed herein. Forward-looking statements reflect the information only as of the date on which they are made. The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information. If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements. This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the consolidated financial statements included under Part II, Item 8 of this annual report on Form 10-K for the year ended December 31, 2020. This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualified by reference to them.
The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2020, 2019 and 2018 should be read in conjunction with our consolidated financial statements and the notes to those statements. Results are impacted by the effects of the Ambit Transaction, the Crius Transaction and the Merger (see Note 2 to the Financial Statements). The discussion and analysis of our financial condition and results of operations for the year ended December 31, 2018 and for the year ended December 31, 2019 compared to the year ended December 31, 2018 are included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 2019 Form 10-K and is incorporated herein by reference except for the operational results from the former ERCOT, PJM, NY/NE and MISO segments that were replaced by the Texas, East, West and Sunset segments in an update of our reportable segments in the third quarter of 2020. Operational results for the Texas, East, West and Sunset segments for the year ended December 31, 2018 and for the year ended December 31, 2019 compared to the year ended December 31, 2018 are included in Results of Operations below to reflect this update of reportable segments.
All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless otherwise indicated.
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. Effective July 2, 2020, we changed our name from Vistra Energy Corp. to Vistra Corp. to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business powering the communities we serve with safe, reliable power.
Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East (iv) West, (v) Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's CODM makes operating decisions, assesses performance and allocates resources. Management believes that the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. See Notes 1 and 20 to the Financial Statements for further information concerning the updates to our reportable business segments.
Significant Activities and Events and Items Influencing Future Performance
Winter Storm Uri
In February 2021, the U.S. experienced an unprecedented winter storm Uri, bringing extreme cold temperatures to the central U.S., including Texas. On February 12, 2021, the Governor of Texas declared a state of disaster for all 254 counties in the State in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide. On February 14, 2021, President Biden issued a federal emergency declaration for all 254 Texas counties.
As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry designed to keep pipes at the power plants from freezing. In addition, in anticipation of winter storm Uri we took additional steps to prepare, including procuring additional demineralized water supply trailers to ensure sufficient water availability to run for extended periods and verifying that freeze protection circuits were operational.
This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event (i.e., involuntary outages to customers across the system for varying periods of time) that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. The biggest challenges to our plants throughout the storm were securing adequate natural gas supplies for our gas plants and the handling of frozen fuel at our coal plants. Despite these challenges, we estimate that our fleet generated approximately 25 to 30% of the power on the grid during the height of the outages, as compared to our approximately 18% market share.
The overall financial impact from winter storm Uri is still being calculated, but Vistra expects it will have a material adverse impact on its financial results driven by generation output being constrained due to challenges with receiving a steady supply of fuel for some plants as well as challenges with handling fuel already on site given the freezing conditions. As a result of these challenges, Vistra had to procure power in the ERCOT market at prices at or near the price cap to meet its supply obligations. While the financial impacts of winter storm Uri to Vistra are not yet finalized, Vistra management preliminarily estimates the one-time adverse impact on pre-tax net income will be in the range of approximately $900 million to $1.3 billion.
This estimated range is preliminary and based on currently available information and management estimates. The final amount of the estimated loss is subject to a variety of factors including, but not limited to, outstanding pricing, load, and settlement data from ERCOT (which is released at various intervals during a period of up to 180 days after the transaction day); the outcome of potential litigation arising from this event (including any litigation that we may pursue or be a party to); 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 that is currently being considered or may be considered by any such parties.
There have already been several announced efforts by the state and federal governments and regulatory agencies to investigate and determine the causes of this event and its impact on consumers. We have received a civil investigative demand from the Attorney General of Texas as well as a request for information from ERCOT related to this event and may receive additional inquiries. We are cooperating with these entities and are working to respond to these requests. Those efforts may result in changes in regulations that impact our industry including but not limited to additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination among the various participants in the electricity supply chain during any future event; potential revisions to the way in which the ERCOT market compensates and incentivizes the continued operation of assets that only run during times of scarcity; and potential changes to the types of plans permitted to be marketed to residential customers. We are continuing to monitor this situation as it develops but at this time cannot estimate any impacts of any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event on our business, financial condition, results of operations, or cash flows.
As of December 31, 2020, Vistra had total available liquidity of approximately $2.4 billion, which was primarily comprised of cash and availability under its revolving credit facility. During this storm event, Vistra was required to post a significant amount of collateral, including to ERCOT, clearinghouses for natural gas and power transactions and other trading counterparties. Despite these posting requirements, Vistra has consistently maintained, and it continues to maintain, sufficient liquidity to conduct its operations in the ordinary course. As of February 25, 2021, Vistra had more than $1.5 billion of cash and availability under its revolving credit facility to meet any of its liquidity needs.
In response to the storm, Vistra committed to donate $5 million to assist Texas communities and individuals meet their most pressing needs, including support for food banks and food pantries, critical needs, bill payment assistance, and more. Vistra also assured residential customers across its retail brands that they will not see any near-term impact on their rates due to the winter weather event, though bills may increase due to high usage during the cold weather period in February.
Investments in Clean Energy and CO2 Reductions
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. We will only invest in these growth projects if we are confident in the expected returns. See Note 3 to the Financial Statements for a summary of our solar and battery energy storage projects.
In September 2020 and December 2020, we announced our intention to retire (a) all of our remaining coal generation facilities in Illinois and Ohio, (b) one coal generation facility in Texas and (c) one natural gas facility in Illinois, no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 13 to the Financial Statements), and in furtherance of our efforts to significantly reduce our carbon footprint. See Note 4 to the Financial Statements for a summary of these planned generation retirements as well as our generation plant retirements in 2019.
With the global outbreak of the novel coronavirus (COVID-19) and the declaration of a pandemic by the World Health Organization on March 11, 2020, 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.
We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic to guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we have taken, and will continue to take, health and safety measures that we determine are necessary in order to mitigate the impacts. To date, as a result of these business continuity measures, the Company has not experienced material disruptions in our operations due to COVID-19.
The fundamentals of the Company remain strong. Vistra believes it has sufficient available liquidity to continue business operations during this volatile period. As described under Available Liquidity, the Company has total available liquidity of $2.399 billion as of December 31, 2020, consisting of cash on hand and available capacity under our revolving credit facility (Revolving Credit Facility) of the Vistra Operations Credit Facilities. In addition, the maturities of our long-term debt are relatively modest until 2023. If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, the Company believes it would have additional alternatives to maintain access to liquidity, including drawing upon available liquidity or reductions to capital expenditures, planned voluntary debt repayments or operating costs. As a result of the Company's ongoing initiatives, the Company believes it is well-positioned to be able to respond to changes in customer demand, regulation or other factors impacting the Company's business related to the COVID-19 pandemic.
In response to the economic and employment impacts of the COVID-19 outbreak, various states have instituted moratoriums or other conditions on disconnections for retail electricity customers. For example, in March and April 2020, the PUCT issued multiple orders requiring REPs in the ERCOT market to suspend late fees for residential customers through May 15, 2020, and to offer deferred payment plans to customers upon request. The PUCT also enacted the COVID-19 Electricity Relief Program whereby REPs must forego disconnecting customers certified as experiencing COVID-19-related hardship, and if such customer would otherwise be subject to disconnection and meets other qualifications, such REP would request suppression of the delivery charges from the transmission and distribution utility and request a proxy energy charge reimbursement from the COVID-19 Electricity Relief Program of $0.04/kWh. The PUCT ceased accepting new enrollments under the COVID-19 Electricity Relief Program after August 31, 2020, and the disconnection protections and financial assistance expired after September 30, 2020.
See Note 7 to the Financial Statements for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.
The COVID-19 pandemic has presented potential new risks to the Company's business. Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's 2020 results of operations. The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level of economic activity in the U.S. and globally. As a result, COVID-19 may have a range of impacts on the Company's operations, the full extent and scope of which are currently unknown. See Part I, Item 1A Risk Factors — The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, and results of operations.
Acquisitions and Merger
Ambit Transaction — On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of Ambit (Ambit Transaction). See Note 2 to the Financial Statements for a summary of the Ambit Transaction and business combination accounting.
Crius Transaction — On July 15, 2019, Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). See Note 2 to the Financial Statements for a summary of the Crius Transaction and business combination accounting.
Dynegy Merger Transaction — On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement. See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting.
In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. See Note 14 to the Financial Statements for more information about our dividend program.
Share Repurchase Program
In September 2020, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $1.5 billion of our outstanding common stock may be repurchased. The Share Repurchase Program was effective January 1, 2021, at which time the Prior Share Repurchase Plan terminated. From January 1, 2021 through February 23, 2021, 5,902,720 shares of our common stock had been repurchased under the Share Repurchase Program for $125 million at an average price per share of common stock of $21.15, and at February 23, 2021, $1.375 billion was available for repurchase under the Share Repurchase Program. See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program and the Prior Share Repurchase Program.
We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities and/or reduce ongoing interest expense. In 2019 and 2020, we completed several transactions, including the redemption and repayment of all of Parent's previously outstanding senior notes, that we believe, in the aggregate, advanced all of these goals. See Note 11 to the Financial Statements for details of our long-term debt activity and Note 10 to the Financial Statements for details of our accounts receivable financing.
PJM — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year:
|(average price per MW-day)|
|RTO zone (a)||$||88.32||$||140.00|
(a)Planning Year 2020-2021 includes Duke Energy Ohio Kentucky (DEOK) zone, which cleared at $130.00 per MW-day. RTO Zone excluding DEOK Zone was $76.53 per MW-day.
Our capacity sales, net of purchases, aggregated by planning year and capacity type through planning year 2022-2023, are as follows:
|CP auction capacity sold, net (MW)||9,065||9,309||125|
|Bilateral capacity sold, net (MW)||100||250||200|
|Total segment capacity sold, net (MW)||9,165||9,559||325|
|Average price per MW-day||$||128.24||$||157.30||$||165.77|
NYISO — The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:
2021 - 2022
|Price per kW-month||$||2.71||$||0.10|
Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades. Our capacity sales, aggregated by season through winter 2022-2023, are as follows:
2020 - 2021
2021 - 2022
2022 - 2023
|Auction capacity sold (MW)||144||—||—||—||—|
|Bilateral capacity sold (MW)||747||843||305||210||71|
|Total capacity sold (MW)||891||843||305||210||71|
|Average price per kW-month||$||0.72||$||2.43||$||0.97||$||1.13||$||1.13|
ISO-NE — The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each planning year:
|Price per kW-month||$||5.30||$||4.63||$||3.80||$||2.00|
Performance incentive rules increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. We continue to market and pursue longer term multi-year capacity transactions that extend through planning year 2024-2025.
|Auction capacity sold (MW)||3,085||2,798||2,996||2,496||—|
|Bilateral capacity sold (MW)||191||170||95||20||20|
|Total capacity sold (MW)||3,276||2,968||3,091||2,516||20|
|Average price per kW-month||$||5.11||$||4.57||$||3.92||$||2.16||$||4.93|
MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year:
|Price per MW-day||$||5.00|
MISO capacity sales through planning year 2023-2024 are as follows:
|Bilateral capacity sold in MISO (MW)||2,672||2,098||573||251|
|CP auction capacity sold in PJM (MW)||—||15||—||—|
|Total MISO segment capacity sold (MW)||2,672||2,113||573||251|
|Average price per kW-month||$||3.04||$||3.12||$||4.05||$||3.69|
CAISO — Our capacity sales, aggregated by calendar year for 2021 through 2022 for Moss Landing, are as follows:
|Bilateral capacity sold (Avg MW)||1,020||831|
Key Operational Risks and Challenges
Following is a discussion of certain key operational risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material effect on our business, results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price for our securities (including our common stock). See also Item 1A. Risk Factors in this annual report on Form 10-K for additional discussion on risks that could have a material effect on our results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price for our securities (including our common stock).
Natural Gas Price and Market Heat Rate Exposure
The price of power is typically set by natural gas-fueled generation facilities, with wholesale prices generally tracking increases or decreases in the price of natural gas, with exceptions such as those periods during which ERCOT power prices rise significantly as a result of the scarcity of available generation resources relative to power demand. In recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas extraction; this supply/demand environment has resulted in historically low natural gas prices, and such prices have historically been volatile.
In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities. Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as wholesale electricity prices change either as a result of changes in natural gas prices or market heat rates, because of the effect on our operating margins. A persistent decline in the price of natural gas, if not offset by an increase in market heat rates, would likely have a material adverse effect on our results of operations, liquidity and financial condition, predominantly related to the production of power generation volumes in excess of the volumes utilized to service our retail customer load requirements and wholesale hedges.
The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Our market heat rate exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and mix of generation assets. For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in the price of natural gas, given their intermittent nature. Decreases in market heat rates decrease the value of our generation assets because lower market heat rates result in lower wholesale electricity prices, and vice versa.
As a result of our exposure to the variability of natural gas prices and market heat rates, retail sales and hedging activities are critical to our operating results and maintaining consistent cash flow levels.
Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position utilizing retail electricity markets as a sales channel. In addition, our approach to managing electricity price risk focuses on the following:
•employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related contracts intended to partially hedge gross margins;
•continuing focus on cost management to better withstand gross margin volatility;
•following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude and costs of commodity price, liquidity risk and retail demand variability; and
•improving retail customer service to attract and retain high-value customers.
We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices that have corresponded to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.
Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments at December 31, 2020 were as follows:
The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MMBtu/MWh) on realized pretax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of December 31, 2020.
|Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price||$||12||$||63|
|Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price||$||(9)||$||(59)|
|Gas Generation: $1.00/MWh increase in spark spread||$||12||$||33|
|Gas Generation: $1.00/MWh decrease in spark spread||$||(9)||$||(30)|
|Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price||$||(13)||$||(15)|
|Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price||$||1||$||3|
|Gas Generation: $1.00/MWh increase in spark spread||$||5||$||38|
|Gas Generation: $1.00/MWh decrease in spark spread||$||(3)||$||(35)|
|Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price||$||(5)||$||(4)|
|Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price||$||5||$||4|
|Gas Generation: $1.00/MWh increase in spark spread||$||—||$||4|
|Gas Generation: $1.00/MWh decrease in spark spread||$||—||$||(4)|
|Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price||$||1||$||1|
|Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price||$||(1)||$||(1)|
|Coal Generation: $2.50/MWh increase in power price||$||5||$||40|
|Coal Generation: $2.50/MWh decrease in power price||$||(1)||$||(34)|
Competitive Retail Markets and Customer Retention
Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch retail electricity providers for various reasons. Based on numbers of meters, our total retail customer counts increased approximately 1% in 2020 and approximately 2% in both 2019 and 2018. Based upon December 31, 2020 results discussed below in Results of Operations, a 1% decline in retail customers in ERCOT would result in a decline in annual revenues of approximately $57 million. In responding to the competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing on the following key initiatives:
•Maintaining competitive pricing initiatives on residential service plans;
•Actively competing for new customers in areas open to competition within ERCOT, while continuing to strive to enhance the experience of our existing customers; we are focused on continuing to implement initiatives that deliver world-class customer service and improve the overall customer experience;
•Establishing and leveraging our TXU EnergyTM brand in the sale of electricity to residential and commercial customers, as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer needs; and
•Focusing market initiatives largely on programs targeted at retaining the existing highest-value customers and to recapturing customers who have switched REPs, including maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy our direct-sales force; tactical programs we have initiated include improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market.
Exposures Related to Nuclear Asset Outages
Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate generation capacity of 1,150 MW. As of December 31, 2020, these units represented approximately 6% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage at the same time, the unfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2021 at December 31, 2020) to be approximately $1 million per day before consideration of any costs to repair the cause of such outages or receipt of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to the Financial Statements to understand the importance and limits of our insurance protection.
The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs and may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down our Comanche Peak units as a precautionary measure.
We participate in industry groups and with regulators to keep current on the latest developments in nuclear safety, operation and maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC, the Institute of Nuclear Power Operations (INPO) and the Nuclear Energy Institute (NEI). We also apply the knowledge gained through our continuing investment in technology, processes and services to improve our operations and to detect, mitigate and protect our nuclear generation assets. Management continues to focus on the safe, reliable and efficient operations at the facility.
Cyber/Data Security and Infrastructure Protection Risk
A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our TXU EnergyTM, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric brands, expose the company to legal claims and regulatory scrutiny or impair our ability to execute on business strategies.
We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to, the U.S. Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC.
While the Company has not experienced a cyber/data event causing any material operational, reputational or financial impact, we recognize the growing threat within the general market place and our industry, and are proactively making strategic investments in our perimeter and internal defenses, cyber/data security operations center and regulatory compliance activities. We also apply the knowledge gained through industry and government organizations to continuously improve our technology, processes and services to detect, mitigate and protect our cyber and data assets.
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results are impacted by extreme or sustained weather conditions and may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme winter weather have made, and may make such fluctuations more pronounced. The pattern of this fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.
Application of Critical Accounting Policies
Our significant accounting policies are discussed in Note 1 to the Financial Statements. We follow accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.
On November 1, 2019, an indirect, wholly owned subsidiary of Vistra completed the Ambit Transaction. On July 15, 2019, an indirect, wholly owned subsidiary of Vistra completed the Crius Transaction. Each of the Ambit Transaction and Crius Transaction, respectively, was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Ambit Acquisition Date and the Crius Acquisition Date, respectively. See Note 2 to the Financial Statements for the purchase price allocations for both the Ambit Transaction and Crius Transaction as well as the related adjustments through the respective measurement periods.
Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The acquired assets that involved the most subjectivity in determining fair value consisted of the customer relationship intangible assets. The assignment of fair value to the identifiable intangible assets requires judgment. We apply an income-based valuation methodology in measuring the customer relationships acquired, which include certain assumptions such as forecasted future cash flows, customer attrition rates, and discount rates. Customer relationship intangibles assets are generally amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which the economic benefits are realized over their estimated useful lives.
On the Merger Date, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation. The Merger was accounted for in accordance with ASC 805, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. Vistra is the acquirer for both federal tax and accounting purposes. The combined results of operations are reported in our consolidated financial statements beginning as of the Merger Date. See Note 2 to the Financial Statements.
The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant and equipment and executory contracts, primarily long-term service agreements for maintenance of power plants, a unit-specific power sales agreement and rail transportation contracts. The fair value of each power plant was estimated using a combination of an income approach and a market approach. The income approach is the present value of future cash flows over the life of each power plant that are based on management’s estimates of revenues and operating expenses, and appropriate discount rates. The estimate of long term prices of electricity and natural gas at each plant location that was used in developing forecasted revenues for the income approach was especially subjective, because as of the Merger Date, limited market information about future prices beyond the year 2022 was available. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the relevant market, with adjustments relating to any differences between the assets and locations. The determination of deferred tax assets was complex as it required assessing income tax rules and regulations and proposed regulations that impose limitations on the future use of acquired net operating losses and other limitations on deductions.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.
Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity, natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 15 to the Financial Statements.
Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the normal purchase or sale election is made. Accounting standards also permit an entity to designate certain qualifying derivative contracts in a hedge accounting relationship, whereby changes in fair value are not recognized immediately in earnings. Vistra does not have derivative instruments with hedge accounting designations.
We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements that we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the 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 derivative contracts rather than collateral.
See Note 16 to the Financial Statements for further discussion regarding derivative instruments.
Accounting for Income Taxes
Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.
See Notes 1 and 7 to the Financial Statements for further discussion of income tax matters.
Accounting for Tax Receivable Agreement
On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent. Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Vistra reflected the obligation associated with TRA Rights at fair value in the amount of $574 million as of the Emergence Date related to these future payment obligations. As of December 31, 2020, the TRA obligation has been adjusted to $450 million. During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA obligation totaling $69 million as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) regulations and the anticipated tax benefits from renewable development projects. At December 31, 2020, expected undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion. The TRA obligation value is the discounted amount of projected payments to be made each year under the TRA, based on certain assumptions, including but not limited to:
•the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the assets subject thereto;
•the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets;
•a blended federal/state corporate income tax rate in all future years of 23.3%;
•future taxable income by year for future years;
•the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise;
•a discount rate of 15%, which represented our view at the Emergence Date of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence; and
•additional states that Vistra now operates in, the relevant tax rates of those states and how income will be apportioned to those states.
We recognize accretion expense over the life of the TRA Rights liability as the present value of the liability is accreted up over the life of the liability. This noncash accretion expense is reported in the consolidated statements of operations as Impacts of Tax Receivable Agreement. Further, there may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items. Changes in those estimates are recognized as adjustments to the related TRA Rights liability, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable Agreement. See Note 8 to the Financial Statements.
Asset Retirement Obligations (ARO)
As part of business combination accounting, new fair values were established for all AROs assumed in the Merger. A liability is initially recorded at fair value for an ARO associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets. Changes to the estimate of the ARO requires us to make significant estimates and assumptions. Specifically, the estimates and assumptions required for the mining land reclamation related to lignite mining, such as the costs to fill in mining pits and interpreting the mining permit closure requirements, are complex and require a significant amount of judgment. To develop the estimate associated with the costs to fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit. A significant portion of the estimate is associated with the Asset Closure Segment, thus related to closed facilities with changes in the estimate recorded to our consolidated statements of operations.
During the years ended December 31, 2020 and 2019, we transferred $15 million and $135 million, respectively, in ARO obligations to third parties for remediation. Any remaining unpaid third-party obligation was reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.
At December 31, 2020, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.585 billion and includes an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate the Comanche Peak facility. The costs to ultimately decommission that facility are recoverable through the regulatory rate making process as part of Oncor's delivery fees and therefore changes in estimates of the ARO do not impact Vistra's earnings.
See Note 21 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during the years ended 2020, 2019 and 2018.
Impairment of Goodwill and Other Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or market heat rates or an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. See Note 21 to the Financial Statements for discussion of impairments of long-lived assets recorded in 2020.
Recoverability of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group, through considering specific assumptions for forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices and forecasted operating costs. The carrying value of such asset groups is determined to be unrecoverable if the projected undiscounted cash flows are less than the carrying value.
If an asset group carrying value is determined to be unrecoverable, fair value will be calculated based on a market participant view and a loss will be recorded for the amount the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, forward capacity prices, market heat rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Another key assumption in the income approach is the discount rate applied to the forecasted cash flows. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets. Additional material impairments related to our generation facilities may occur in the future if forward wholesale electricity prices decline in the markets in which we operate in or if additional environmental regulations increase the cost of producing electricity at our generation facilities.
Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, respectively, are required to be evaluated for impairment at least annually (we have selected October 1 as our annual goodwill test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit. If the entity determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is required. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2020. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition, interest rates and changes in reporting unit book value.
Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2020, $2.461 billion of our goodwill was allocated to our Retail reporting unit and $122 million was allocated to our Texas Generation reporting unit. Goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit's assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.
The determination of enterprise value of a reporting unit involves a number of assumptions and estimates. We use a combination of fair value measurements to estimate enterprise values of our reporting units including: internal discounted cash flow analyses (income approach), and comparable publicly traded company values (market approach). The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and retail sales volume trends, as well as determination of a terminal value. Another key variable in the income approach is the discount rate, or weighted average cost of capital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. The market approach involves using trading multiples of EBITDA of those selected publicly traded companies to derive appropriate multiples to apply to the EBITDA of our reporting units. Critical judgments include the selection of publicly traded comparable companies and the weighting of the value metrics in developing the best estimate of enterprise value.
RESULTS OF OPERATIONS
Vistra Consolidated Financial Results — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 and Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
|Year Ended December 31,||2020 vs 2019|
|2019 vs 2018|
|Fuel, purchased power costs and delivery fees||(5,174)||(5,742)||(5,036)||568||(706)|
|Depreciation and amortization||(1,737)||(1,640)||(1,394)||(97)||(246)|
|Selling, general and administrative expenses||(1,035)||(904)||(926)||(131)||22|
|Impairment of long-lived assets||(356)||—||—||(356)||—|
|Interest expense and related charges||(630)||(797)||(572)||167||(225)|
|Impacts of Tax Receivable Agreement||5||(37)||(79)||42||42|
|Equity in earnings of unconsolidated investment||4||16||17||(12)||(1)|
|Income (loss) before income taxes||890||1,216||(101)||(326)||1,317|
|Income tax (expense) benefit||(266)||(290)||45||24||(335)|
|Net income (loss)||$||624||$||926||$||(56)||$||(302)||$||982|
|Year Ended December 31, 2020|
|Eliminations / Corporate and Other||Vistra Consolidated|
|Fuel, purchased power costs and delivery fees||(6,857)||(1,078)||(1,262)||(168)||(704)||—||4,895||(5,174)|
|Depreciation and amortization||(303)||(475)||(721)||(19)||(133)||(22)||(64)||(1,737)|
|Selling, general and administrative expenses||(675)||(75)||(89)||(26)||(71)||(27)||(72)||(1,035)|
|Impairment of long-lived assets||—||—||—||—||(356)||—||—||(356)|
|Operating income (loss)||312||1,761||73||39||(420)||(109)||(137)||1,519|
|Interest expense and related charges||(10)||8||(7)||10||(2)||—||(629)||(630)|
|Impacts of Tax Receivable Agreement||—||—||—||—||—||—||5||5|
|Equity in earnings of unconsolidated investment||—||—||4||—||—||—||—||4|
|Income (loss) before income taxes||309||1,760||41||50||(414)||(101)||(755)||890|
|Income tax expense||—||—||—||—||—||—||(266)||(266)|
|Net income (loss)||$||309||$||1,760||$||41||$||50||$||(414)||$||(101)||$||(1,021)||$||624|
|Year Ended December 31, 2019|
|Eliminations / Corporate and Other||Vistra Consolidated|
|Fuel, purchased power costs and delivery fees||(5,816)||(1,283)||(1,393)||(187)||(767)||(267)||3,971||(5,742)|
|Depreciation and amortization||(292)||(472)||(680)||(19)||(120)||—||(57)||(1,640)|
|Selling, general and administrative expenses||(538)||(76)||(83)||(17)||(78)||(43)||(69)||(904)|
|Operating income (loss)||155||1,314||398||88||271||(107)||(126)||1,993|
|Interest expense and related charges||(21)||8||(13)||—||(4)||—||(767)||(797)|
|Impacts of Tax Receivable Agreement||—||—||—||—||—||—||(37)||(37)|
|Equity in earnings of unconsolidated investment||—||—||16||—||—||—||—||16|
|Income (loss) before income taxes||134||1,342||400||88||274||(109)||(913)||1,216|
|Income tax expense||—��||—||—||—||—||—||(290)||(290)|
|Net income (loss)||$||134||$||1,342||$||400||$||88||$||274||$||(109)||$||(1,203)||$||926|
|Year Ended December 31, 2018|
|Eliminations / Corporate and Other||Vistra Consolidated|
|Fuel, purchased power costs and delivery fees||(4,126)||(1,461)||(1,131)||(134)||(505)||(286)||2,607||(5,036)|
|Depreciation and amortization||(318)||(390)||(519)||(14)||(81)||—||(72)||(1,394)|
|Selling, general and administrative expenses||(424)||(88)||(71)||(8)||(50)||(39)||(246)||(926)|
|Operating income (loss)||690||(103)||10||35||242||(63)||(320)||491|
|Interest expense and related charges||(7)||(12)||(10)||(1)||(1)||—||(541)||(572)|
|Impacts of Tax Receivable Agreement||—||—||—||—||—||—||(79)||(79)|
|Equity in earnings of unconsolidated investment||—||—||18||—||—||—||(1)||17|
|Income (loss) before income taxes||712||(88)||18||34||242||(62)||(957)||(101)|
|Income tax benefit||—||—||—||—||—||—||45||45|
|Net income (loss)||$||712||$||(88)||$||18||$||34||$||242||$||(62)||$||(912)||$||(56)|
In 2020, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner during a period of significant economic disruption. Our performance reflected the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business, to produce results that exceeded expectations and generated significant cash from operations of $3.337 billion for the year ended December 31, 2020. The increase of 22% versus 2019 was particularly strong given the general uncertainty in the overall economy and the challenges of dealing with COVID-19.
Consolidated results decreased $302 million to net income of $624 million in the year ended December 31, 2020 compared to the year ended December 31, 2019. The change in results was driven by a $465 million pre-tax decrease in unrealized gains on commodity hedging transactions, a $356 million pre-tax impairment of assets related to our Kincaid, Zimmer and Joppa/EEI coal generation facilities and a $29 million pre-tax loss on disposal of our equity method investment in NELP, offset by strong operating results, particularly in the Texas segment, and the addition of Crius and Ambit. See Note 21 to the Financial Statements.
Operating costs increased $92 million to $1.622 billion in the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily driven by higher estimated costs for ARO, increased LTSA costs and COVID-related expenses and increased operating costs in Retail driven by the acquisition of Ambit and Crius, partially offset by lower property taxes.
SG&A expense increased $131 million to $1.035 billion in the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to the increased expense resulting from the acquisition of Crius in July 2019 and Ambit in November 2019.
Interest expense and related charges decreased $167 million to $630 million in the year ended December 31, 2020 compared to the year ended December 31, 2019 driven by a $109 million decrease in interest paid/accrued reflecting the reduction in higher interest Vistra senior unsecured notes through the Redemptions and Tender Offers in 2019 and 2020 and a $65 million decrease in unrealized mark-to-market losses on interest rate swaps. Debt extinguishment gains totaled $17 million and $21 million in the years ended December 31, 2020 and 2019, respectively. See Note 21 to the Financial Statements.
For the years ended December 31, 2020 and 2019, the impacts of the TRA totaled income of $5 million and expense of $37 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.
For the year ended December 31, 2020, income tax expense totaled $266 million and the effective tax rate was 29.9%. For the year ended December 31, 2019, income tax benefit totaled $290 million and the effective tax rate was 23.8%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.
For the years ended December 31, 2020 and 2019, consolidated cash flows from operations totaled $3.337 billion and $2.736 billion, respectively.
Discussion of Adjusted EBITDA
Non-GAAP Measures — In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our segments for the period presented. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts of mark-to-market changes on derivatives, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other material nonrecurring or unusual items.
Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.
When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).
Adjusted EBITDA — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 and Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
|Year Ended December 31,||2020 vs 2019|
|2019 vs 2018|
|Net income (loss)||$||624||$||926||$||(56)||$||(302)||$||982|
|Income tax expense (benefit)||266||290||(45)||(24)||335|
|Interest expense and related charges (a)||630||797||572||(167)||225|
|Depreciation and amortization (b)||1,812||1,713||1,472||99||241|
|Unrealized net (gain) loss resulting from commodity hedging transactions||(231)||(696)||380||465||(1,076)|
|Generation plant retirement expenses||43||54||—||(11)||54|
|Fresh start/purchase accounting impacts||38||30||41||8||(11)|
|Impacts of Tax Receivable Agreement||(5)||37||79||(42)||(42)|
|Non-cash compensation expenses||63||48||73||15||(25)|
|Transition and merger expenses||16||115||233||(99)||(118)|
|Impairment of long-lived assets||356||—||—||356||—|
|Loss on disposal of investment in NELP||29||—||—||29||—|
|COVID-19-related expenses (c)||25||—||—||25||—|
|Odessa earnout buybacks||—||—||18||—||(18)|
(a)Includes unrealized mark-to-market net losses on interest rate swaps of $155 million, $220 million and $5 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(b)Includes nuclear fuel amortization in the Texas segment of $75 million, $73 million and $78 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(c)Includes material and supplies and other incremental costs related to our COVID-19 response.
Vistra recorded its strongest performance in 2020 with Adjusted EBITDA of $3.685 billion, up nearly 11% versus 2019, despite economic challenges and uncertainties dealing with COVID-19. This performance exceeded our expectations set prior to the onset of the pandemic. Our balanced business was driven by strong performance in our Retail segment, delivering $983 million of Adjusted EBITDA, and our Texas generation segment, which delivered $1.646 billion of Adjusted EBITDA. Our other segments, including East, West, Sunset, Asset Closure and Corp delivered $1.056 billion. The performance of our Retail business on a variety of metrics, including customer satisfaction, customer count and margin are all strong. In Generation, we exceeded our commercial availability and safety targets. Our people drove strong results through our Operations Performance Initiative driving incremental gross margin and cost reduction opportunities, and our Best Defense safety program. Finally, our Commercial team optimized our integrated operations through disciplined risk management and hedging activities to ensure we lock in value for our generation business, while cost effectively supplying our retail business. This strong collaboration among our segments has produced consistent, strong results in each year since Vistra became a public company in 2016.
|Year Ended December 31, 2020|
|Eliminations / Corporate and Other||Vistra|
|Net income (loss)||$||309||$||1,760||$||41||$||50||$||(414)||$||(101)||$||(1,021)||$||624|
|Income tax expense||—||—||—||—||—||—||266||266|
|Interest expense and related charges (a)||10||(8)||7||(10)||2||—||629||630|
|Depreciation and amortization (b)||303||550||721||19||133||22||64||1,812|
|Unrealized net (gain) loss resulting from commodity hedging transactions||340||(691)||15||10||95||—||—||(231)|
|Generation plant retirement expenses||—||—||—||—||43||—||—||43|
|Fresh start/purchase accounting impacts||5||(8)||22||—||19||—||—||38|
|Impacts of Tax Receivable Agreement||—||—||—||—||—||—||(5)||(5)|
|Non-cash compensation expenses||—||—||—||—||—||—||63||63|
|Transition and merger expenses||5||2||1||—||—||(3)||11||16|
|Impairment of long-lived assets||—||—||—||—||356||—||—||356|
|Loss on disposal of investment in NELP||—||—||29||—||—||—||—||29|
|COVID-19-related expenses (c)||—||15||3||—||5||—||2||25|
(a)Includes $155 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $75 million in the Texas segment.
(c)Includes material and supplies and other incremental costs related to our COVID-19 response.
|Year Ended December 31, 2019|
|Eliminations / Corporate and Other||Vistra|
|Net income (loss)||$||134||$||1,342||$||400||$||88||$||274||$||(109)||$||(1,203)||$||926|
|Income tax expense||—||—||—||—||—||—||290||290|
|Interest expense and related charges (a)||21||(8)||13||—||4||—||767||797|
|Depreciation and amortization (b)||292||545||680||19||120||—||57||1,713|
|Unrealized net (gain) loss resulting from commodity hedging transactions||278||(591)||(196)||(41)||(146)||—||—||(696)|
|Generation plant retirement expenses||—||—||—||—||12||42||—||54|
|Fresh start/purchase accounting impacts||23||(4)||4||(4)||14||(3)||—||30|
|Impacts of Tax Receivable Agreement||—||—||—||—||—||—||37||37|
|Non-cash compensation expenses||—||—||—||—||—||—||48||48|
|Transition and merger expenses||49||11||9||1||22||—||23||115|
(a)Includes $220 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $73 million in the Texas segment.
|Year Ended December 31, 2018|
|Eliminations / Corporate and Other||Vistra|
|Net income (loss)||$||712||$||(88)||$||18||$||34||$||242||$||(62)||$||(912)||$||(56)|
|Income tax benefit||—||—||—||—||—||—||(45)||(45)|
|Interest expense and related charges (a)||7||12||10||(1)||1||—||543||572|
|Depreciation and amortization (b)||318||468||519||14||81||—||72||1,472|
|Unrealized net (gain) loss resulting from commodity hedging transactions||(206)||498||81||15||(8)||—||—||380|
|Fresh start/purchase accounting impacts||26||(4)||11||—||7||1||—||41|
|Impacts of Tax Receivable Agreement||—||—||—||—||—||—||79||79|
|Non-cash compensation expenses||—||—||—||—||—||—||73||73|
|Transition and merger expenses||1||9||16||1||9||2||195||233|
|Odessa earnout buybacks||—||18||—||—||—||—||—||18|
(a)Includes $5 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $78 million in the Texas segment.
Retail Segment — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
|Year Ended December 31,||Favorable (Unfavorable)|
|Revenues in ERCOT||$||5,880||$||5,061||$||819|
|Revenues in Northeast/Midwest||2,406||1,818||588|
|Total operating revenues||$||8,270||$||6,872||$||1,398|
|Fuel, purchased power costs and delivery fees:|
|Purchases from affiliates||(4,566)||(3,571)||(995)|
|Unrealized net losses on hedging activities with affiliates||(329)||(305)||(24)|
|Unrealized net gains on hedging activities||—||19||(19)|
|Other costs (a)||(69)||(330)||261|
|Total fuel, purchased power costs and delivery fees||$||(6,857)||$||(5,816)||$||(1,041)|
|Retail sales volumes (GWh):|
|Retail electricity sales volumes:|
|Sales volumes in ERCOT||54,075||47,345||6,730|
|Sales volumes in Northeast/Midwest||36,274||30,255||6,019|
|Total retail electricity sales volumes||90,349||77,600||12,749|
|Weather (North Texas average) - percent of normal (b):|
|Cooling degree days||90.0||%||96.0||%|
|Heating degree days||91.0||%||113.0||%|
(a)For the year ended December 31, 2020 and 2019, includes third-party fuel and power purchases of $69 million and $329 million, respectively.
(b)Weather data is obtained from Weatherbank, Inc. For the year ended December 31, 2020, normal is defined as the average over the 10-year period from December 2010 to December 2019. For the year ended December 31, 2019, normal is defined as the average over the 10-year period from December 2009 to December 2018.
Net income increased by $175 million to $309 million and Adjusted EBITDA increased by $176 million to $983 million in the year ended December 31, 2020 compared to the year ended December 31, 2019.
|Year Ended December 31, 2020 Compared to 2019|
|Margin primarily driven by the addition of Crius acquired in July 2019 and Ambit acquired in November 2019||$||339|
|Other driven by higher operating costs and SG&A expense (including bad debt expense) primarily due to the addition of Crius and Ambit||(162)|
|Change in Adjusted EBITDA||$||177|
|Change in depreciation and amortization expenses driven by Crius/Ambit intangibles||(11)|
|(Unfavorable) impact of higher unrealized net losses on commodity hedging activities||(62)|
|Lower transition and merger and other expenses||71|
|Change in Net income||$||175|
Generation — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
|Year Ended December 31,|
|Capacity revenue from ISO/RTO||—||—||(52)||170||—||—||164||197|
|Sales to affiliates||2,543||2,213||1,655||1,074||3||—||365||285|
|Rolloff of unrealized net gains (losses) representing positions settled in the current period||2||371||159||59||(22)||(10)||(205)||(74)|
|Unrealized net gains (losses) on hedging activities||217||72||(121)||(44)||12||51||133||249|
|Unrealized net gains (losses) on hedging activities with affiliates||458||132||(61)||180||—||—||(68)||(7)|
|Fuel, purchased power costs and delivery fees:|
|Fuel for generation facilities and purchased power costs||(960)||(1,117)||(1,225)||(1,381)||(166)||(187)||(744)||(739)|
|Fuel for generation facilities and purchased power costs from affiliates||6||—||(8)||(2)||—||—||2||2|
|Unrealized (gains) losses from hedging activities||14||16||8||1||—||—||45||(22)|
|Ancillary and other costs||(138)||(182)||(37)||(11)||(2)||—||(7)||(8)|
|Fuel, purchased power costs and delivery fees||(1,078)||(1,283)||(1,262)||(1,393)||(168)||(187)||(704)||(767)|
|Net income (loss)||$||1,760||$||1,342||$||41||$||400||$||50||$||88||$||(414)||$||274|
|Production volumes (GWh):|
|Natural gas facilities||35,093||39,433||55,938||55,555||5,284||5,228|
|Lignite and coal facilities||26,013||24,558||29,971||34,424|
|Lignite and coal facilities||77.1||%||72.8||%||47.1||%||54.1||%|
|Weather - percent of normal (a):|
|Cooling degree days||98||%||99||%||105||%||103||%||130||%||104||%||102||%||110||%|
|Heating degree days||85||%||111||%||92||%||101||%||95||%||105||%||89||%||99||%|
(a)Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data.
|Year Ended December 31,||Year Ended December 31,|
|Market pricing||Average Market On-Peak Power Prices ($MWh) (b):|
|Average ERCOT North power price ($/MWh)||$||21.46||$||35.93||PJM West Hub||$||24.55||$||30.87|
|AEP Dayton Hub||$||24.49||$||31.02|
|Average NYMEX Henry Hub natural gas price ($/MMBtu)||$||1.99||$||2.51||NYISO Zone C||$||19.37||$||25.90|
|Average natural gas price (a):||Indiana Hub||$||26.77||$||31.23|
|TetcoM3 ($/MMBtu)||$||1.59||$||2.39||Northern Illinois Hub||$||22.47||$||28.16|
|Algonquin Citygates ($/MMBtu)||$||2.00||$||3.17|
(a)Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
(b)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
The following table presents changes in net income (loss) and Adjusted EBITDA for the year ended December 31, 2020 compared to the year ended December 31, 2019.
|Year Ended December 31, 2020 Compared to 2019|
|Favorable/(unfavorable) change in revenue net of fuel||$||390||$||(35)||$||18||$||(39)|
|Favorable/(unfavorable) change in other operating costs||(20)||(15)||(3)||(4)|
|Favorable/(unfavorable) change in SG&A expenses||(7)||(7)||(6)||(22)|
|Change in Adjusted EBITDA||$||339||$||(76)||$||10||$||(66)|
|Unfavorable change in depreciation and amortization||(5)||(41)||—||(13)|
|Change in unrealized net gains/(losses) on commodity hedging activities||100||(211)||(51)||(241)|
|Fresh start/purchase accounting impacts||4||(18)||(4)||(5)|
|Transition and merger expenses||9||8||1||22|
|Impairment of long-lived assets||—||—||—||(356)|
|Generation plant retirement expenses||—||—||—||(31)|
|Loss on disposal of investment in NELP||—||(29)||—||—|
|Other (including interest and COVID-19 related expenses)||(29)||8||6||2|
|Change in Net income||$||418||$||(359)||$||(38)||$||(688)|
The change in Texas segment results was driven by higher realized prices through hedging activities and plant optimization efforts and unrealized hedging gains, partially offset by lower insurance reimbursement and COVID-19 related expenses in the current year.
The change in East segment results was driven by lower capacity revenue, unrealized hedging losses in current year versus unrealized hedging gains in prior year, loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 21 to the Financial Statements) and COVID-19 related expenses in the current year.
The change in West segment results was driven by unrealized hedging losses in current year versus unrealized hedging gains in prior year, partially offset by higher realized prices through hedging activities and plant optimization efforts.
The change in Sunset segment results was driven by impairment of assets related to our Kincaid, Zimmer and Joppa/EEI coal generation facilities and related generation plant retirement expenses, unrealized hedging losses in current year versus unrealized hedging gains in prior year, lower capacity revenue, and higher operating costs.
Generation — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
|Year Ended December 31,|
|Capacity revenue from ISO/RTO||—||—||170||375||—||30||197||258|
|Sales to affiliates||2,213||1,819||1,074||614||—||—||285||168|
|Rolloff of unrealized net gains (losses) representing positions settled in the current period||371||404||59||3||(10)||20||(74)||60|
|Unrealized net gains (losses) on hedging activities||72||(689)||(44)||(43)||51||(35)||249||(87)|
|Unrealized net gains (losses) on hedging activities with affiliates||132||(198)||180||(36)||—||—||(7)||16|
|Fuel, purchased power costs and delivery fees:|
|Fuel for generation facilities and purchased power costs||(1,117)||(1,307)||(1,381)||(1,111)||(187)||(132)||(739)||(547)|
|Fuel for generation facilities and purchased power costs from affiliates||—||—||(2)||(8)||—||—||2||30|
|Unrealized (gains) losses from hedging activities||16||(15)||1||(5)||—||—||(22)||19|
|Ancillary and other costs||(182)||(139)||(11)||(7)||—||(2)||(8)||(7)|
|Fuel, purchased power costs and delivery fees||(1,283)||(1,461)||(1,393)||(1,131)||(187)||(134)||(767)||(505)|
|Net income (loss)||$||1,342||$||(88)||$||400||$||18||$||88||$||34||$||274||$||242|
|Production volumes (GWh):|
|Natural gas facilities||39,433||35,790||55,555||41,036||5,228||3,664|
|Lignite and coal facilities||24,558||26,243||34,424||29,734|
|Lignite and coal facilities||72.8||%||77.8||%||54.1||%||63.4||%|
|Weather - percent of normal (a):|
|Cooling degree days||99||%||100||%||103||%||120||%||105||%||105||%||110||%||134||%|
|Heating degree days||111||%||113||%||101||%||103||%||105||%||86||%||99||%||97||%|
(a)Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data.
|Year Ended December 31,||Year Ended December 31,|
|Market pricing||Average Market On-Peak Power Prices ($MWh) (b):|
|Average ERCOT North power price ($/MWh)||$||35.93||$||29.96||PJM West Hub||$||30.87||$||41.79|
|AEP Dayton Hub||$||31.02||$||40.47|
|Average NYMEX Henry Hub natural gas price ($/MMBtu)||$||2.51||$||3.12||NYISO Zone C||$||25.90||$||37.03|
|Average natural gas price (a):||Indiana Hub||$||31.23||$||39.01|
|TetcoM3 ($/MMBtu)||$||2.39||$||3.69||Northern Illinois Hub||$||28.16||$||34.46|
|Algonquin Citygates ($/MMBtu)||$||3.17||$||4.84|
(a)Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
(b)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
The following table presents changes in net income and Adjusted EBITDA for the year ended December 31, 2019 compared to the year ended December 31, 2018.
|Year Ended December 31, 2019 Compared to 2018|
|Favorable impact related to operations acquired in the Merger (a)||$||—||$||268||$||20||$||84|
|Favorable/(unfavorable) change in revenue net of fuel||421||10||(11)||(159)|
|Favorable/(unfavorable) change in other operating costs||(28)||(13)||(4)||41|
|Favorable/(unfavorable) change in SG&A expenses||9||(11)||(7)||1|
|Change in Adjusted EBITDA||$||395||$||245||$||(2)||$||(33)|
|Unfavorable change in depreciation and amortization||(77)||(161)||(5)||(39)|
|Change in unrealized net gains on commodity hedging activities||1,089||277||56||138|
|Fresh start/purchase accounting impacts||—||7||4||(7)|
|Transition and merger expenses||(2)||7||—||(13)|
|Generation plant retirement expenses||—||—||—||(12)|
|Impact of Odessa earnout buybacks||18||—||—||—|
|Other (including interest)||7||7||1||(2)|
|Change in Net income||$||1,430||$||382||$||54||$||32|
The change in Texas segment results was driven by higher realized prices through hedging activities and plant optimization efforts, unrealized gains in 2019 versus unrealized losses in 2018, insurance reimbursement received in 2019, and the Odessa earnout buybacks in 2018.
The change in East segment results was driven by operations in the first quarter of 2019 acquired in the Merger, partially offset by lower generation in the second through fourth quarters.
The change in West segment results was driven by operations in the first quarter of 2019 acquired in the Merger and unrealized hedging gains in 2019 versus unrealized hedging losses in 2018.
The change in Sunset segment results was driven by operations in the first quarter of 2019 acquired in the Merger and unrealized hedging gains in 2019, partially offset by decrease in revenue net of fuel reflecting lower realized power prices and capacity revenue.
Asset Closure Segment — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
|Year Ended December 31,||Favorable (Unfavorable)|
|Fuel, purchased power costs and delivery fees||—||(267)||267|
|Depreciation and amortization||(22)||—||(22)|
|Selling, general and administrative expenses||(27)||(43)||16|
|Production volumes (GWh)||—||7,484||(7,484)|
Results for the Asset Closure segment primarily reflect the retirement of the Coffeen, Duck Creek, Havana and Hennepin plants in November and December 2019, respectively, the retirement of the Northeastern waste coal plant in October 2018, retirement of the Stuart and Killen plants in May 2018 (acquired in the Merger), and the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018, respectively (see Note 4 to the Financial Statements). Operating costs for the years ended December 31, 2020 and 2019 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines.
Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2020 and 2019. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $231 million and $696 million in unrealized net gains for the year ended December 31, 2020 and 2019, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.
|Year Ended December 31,|
|Commodity contract net liability at beginning of period||$||(279)||$||(850)|
|Settlements/termination of positions (a)||(14)||358|
|Changes in fair value of positions in the portfolio (b)||245||338|
|Acquired commodity contracts (c)||—||(28)|
|Other activity (d)||(27)||(97)|
|Commodity contract net liability at end of period||$||(75)||$||(279)|
(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The years ended December 31, 2020 and 2019 include reversals of $1 million of previously recorded unrealized losses and $3 million of previously recorded unrealized gains related to Vistra beginning balances. respectively. The years ended December 31, 2020 and 2019 also include reversals of $12 million and $124 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Transaction and Ambit Transaction. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(b)Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(c)Includes fair value of commodity contracts acquired on the Ambit Acquisition Date and the Crius Acquisition Date in 2019 (see Note 2 to the Financial Statements).
(d)Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.
Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at December 31, 2020, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
|Maturity dates of unrealized commodity contract net liability at December 31, 2020|
|Source of fair value||Less than|
|1-3 years||4-5 years||Excess of|
|Prices actively quoted||$||(41)||$||(80)||$||(5)||$||—||$||(126)|
|Prices provided by other external sources||30||(2)||1||—||29|
|Prices based on models||107||23||(43)||(65)||22|
Operating Cash Flows
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 — Cash provided by operating activities totaled $3.337 billion and $2.736 billion in the years ended December 31, 2020 and 2019, respectively. The favorable change of $601 million reflects the strong operating performance of both the Texas and Retail segments. Additionally, the increase in operating cash flows includes a lower increase in working capital, lower cash interest paid and increased income taxes received, partially offset by an increase in cash margin deposits posted with third-parties.
Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $311 million, $236 million and $139 million for the year ended December 31, 2020, 2019 and 2018, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.
Investing Cash Flows
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 — Cash used in investing activities totaled $1,572 million and $1.717 billion in the years ended December 31, 2020 and 2019, respectively. Capital expenditures totaled $1.259 billion and $713 million in the years ended December 31, 2020 and 2019, respectively. Cash used in investing activities in the year ended December 31, 2020 and 2019 also reflected net purchases of environmental allowances of $339 million and $125 million, respectively. Cash used in investing activities in the year ended December 31, 2019 also reflected $880 million of net cash paid in the Crius and Ambit Transactions.
Capital Expenditures — In the years ended December 31, 2020 and 2019, capital expenditures consisted of:
|Year Ended December 31,|
|Capital expenditures, including LTSA prepayments||$||770||$||520|
|Nuclear fuel purchases||88||89|
|Growth and development expenditures||401||104|
Financing Cash Flows
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 — Cash used in financing activities totaled $1.796 billion and $1.237 billion in the years ended December 31, 2020 and 2019, respectively. The change was primarily driven by:
•issuance of $5.7 billion principal amount of Vistra Operations senior secured and unsecured notes in 2019;
•redemption of $747 million principal amount of outstanding Vistra Unsecured Senior Notes in 2020;
•net repayments of $350 million in short-term borrowings under the Revolving Credit Facility in 2020 compared to $350 million in net short-term borrowings under the Revolving Credit Facility in 2019;
•net repayments of $150 million under the Receivables Facility in 2020 compared to net borrowings of $111 million in 2019; and
•repayment of $100 million of term loans under the Vistra Operations Credit Facilities in 2020,
partially offset by:
•cash tender offers and early redemptions to purchase approximately $3.0 billion of senior unsecured notes assumed in the Merger in 2019;
•repayment of approximately $3.1 billion of term loans under the Vistra Operations Credit Facilities in 2019;
•$656 million in cash paid for share repurchases in in 2019; and
•$186 million decrease in debt tender offer and other financing fees in 2020 compared to 2019.
See Note 10 to the Financial statements for details of the Receivables Facility and Repurchase Facility and Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.
The following table summarizes changes in available liquidity for the year ended December 31, 2020:
|December 31, 2020||December 31, 2019||Change|
|Cash and cash equivalents||$||406||$||300||$||106|
|Vistra Operations Credit Facilities — Revolving Credit Facility||1,988||1,426||562|
|Vistra Operations — Alternate Letter of Credit Facility||5||—||5|
|Total available liquidity (a)||$||2,399||$||1,726||$||673|
(a)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 10 to the Financial Statements for detail on our account receivable financing.
The $673 million increase in available liquidity for the year ended December 31, 2020 was primarily driven by cash from operations, repayments of cash borrowings under the Revolving Credit Facility and a reduction of letters of credit outstanding under the Revolving Credit Facility reflecting the issuance of $303 million of letters of credit under the Secured LOC Facilities, partially offset by $1.259 billion of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $747 million principal amount of outstanding Vistra Unsecured Senior Notes redeemed in 2020, $266 million in dividends paid to stockholders, the maturity of a $250 million Alternate LOC Facility and $100 million of term loans under the Vistra Operation Credit Facility repaid in March 2020.
During the winter storm Uri event, Vistra was required to post a significant amount of collateral, including to ERCOT, clearinghouses for natural gas and power transactions and other trading counterparties. Despite these posting requirements, Vistra has consistently maintained, and it continues to maintain, sufficient liquidity to conduct its operations in the ordinary course. As of February 25, 2021, Vistra had more than $1.5 billion of cash and availability under its revolving credit facility to meet any of its liquidity needs. In February 2021, we borrowed $600 million under the Revolving Credit Facility to fund our general corporate needs, including posting requirements in connection with the expected impacts of winter storm Uri.
Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements, including those related to our capital allocation initiatives, through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year.
Estimated capital expenditures and nuclear fuel purchases for 2021 are expected to total approximately $1.379 billion and include:
•$575 million for investments in generation and mining facilities;
•$108 million for nuclear fuel purchases;
•$9 million for information technology and other corporate investments; and
•$687 million for growth and development expenditures.
Liquidity Effects of Commodity Hedging and Trading Activities
We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 11 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.
Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.
At December 31, 2020, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:
•$257 million in cash has been posted with counterparties as compared to $202 million posted at December 31, 2019;
•$33 million in cash has been received from counterparties as compared to $8 million received at December 31, 2019;
•$878 million in letters of credit have been posted with counterparties as compared to $1.150 billion posted at December 31, 2019; and
•$18 million in letters of credit have been received from counterparties as compared to $17 million received at December 31, 2019.
Income Tax Payments
In the next 12 months, we do not expect to make federal income tax payments due to Vistra's use of NOL carryforwards. We expect to make approximately $56 million in state income tax payments, offset by $9 million in state tax refunds, and $3 million in TRA payments in the next 12 months.
For the year ended December 31, 2020, we received refunds of $170 million related to AMT credits. For the year ended December 31, 2020, there were no federal income tax payments, $40 million in state income tax payments, $10 million in state income tax refunds and less than $1 million in TRA payments.
Our capitalization ratios consisted of 52% and 56% long-term debt (less amounts due currently) and 48% and 44% stockholders' equity at December 31, 2020 and 2019, respectively. Total long-term debt (including amounts due currently) to capitalization was 53% and 57% at December 31, 2020 and 2019, respectively.
The Credit Facilities Agreement includes a covenant, 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), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00. Although the period ended December 31, 2020 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date.
See Note 11 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.
Collateral Support Obligations
The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.
The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at December 31, 2020, Vistra has posted letters of credit in the amount of $102 million with the PUCT, which is subject to adjustments.
The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $290 million in the form of letters of credit, $10 million in the form of a surety bond and $1 million of cash at December 31, 2020 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).
Material Cross-Default/Acceleration Provisions
Certain of our contractual arrangements contain provisions that could result in an event of default if there was a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referred to as "cross-default" or "cross-acceleration" provisions.
A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances (approximately $2.57 billion at December 31, 2020) under such facilities.
Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross-default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.
Under the Vistra Operations Senior Unsecured Indentures and the Vistra Operations Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.
Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.
The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy or any of the other Originators, in a principal amount of at least $50 million, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated.
The Repurchase Facility contains a cross-default provision. The cross-default provision applies, among other instances, if an event of default (or similar event) occurs under the Receivables Facility or the Vistra Operations Credit Facilities. If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated.
Under the Alternate LOC Facilities, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Alternate LOC Facilities.
Under the Secured LOC Facilities, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Secured LOC Facilities.
Guarantor Summary Financial Information
During the year ended December 31, 2020, we fully redeemed the Vistra Senior Unsecured Notes that were previously guaranteed by substantially all of our wholly owned subsidiaries. The following tables summarize the combined financial information of (i) Vistra Corp. (Parent), which is the ultimate parent company and issuer of the Vistra Senior Unsecured Notes with effect as of the Merger Date, on a stand-alone, unconsolidated basis and (ii) the guarantor subsidiaries of Vistra (Guarantor Subsidiaries). The Guarantor Subsidiaries consist of the wholly owned subsidiaries, which jointly, severally, fully and unconditionally, guaranteed the payment obligations under the Vistra Senior Unsecured Notes. See Note 11 to the Financial Statements for discussion of the Vistra Senior Unsecured Notes and Note 14 to the Financial Statements for discussion of dividend restrictions of Vistra Operations (a guarantor subsidiary of Vistra) and Parent.
This financial information should be read in conjunction with the consolidated financial statements and notes thereto of Vistra. Transactions between the Parent and the Guarantor Subsidiaries have been eliminated. The inclusion of Vistra's subsidiaries as Guarantor Subsidiaries in the summary financial information is determined as of the most recent balance sheet date presented.
The Parent files a consolidated U.S. federal income tax return. All consolidated income tax expense or benefits and deferred tax assets and liabilities are included in the Guarantor summary financial information presented below, with no allocation made to the non-guarantor subsidiaries. Additionally, all corporate shared service costs are included in the Guarantor summary financial information with no allocation to the non-guarantor subsidiaries.
December 31, 2020
|Net income attributable to Vistra||$||678|
|December 31, 2020||December 31, 2020|
|Current assets||$||2,404||Current liabilities||$||1,828|
|Noncurrent assets||21,307||Noncurrent liabilities||13,599|
|Total assets||$||23,711||Total liabilities||$||15,427|
Contractual Obligations and Commitments
See Note 11 to the Financial Statements for long-term debt maturities, Note 12 to the Financial Statements for maturities of lease liabilities and Note 13 to the Financial Statements for commitments related to long-term service and maintenance contracts, energy-related contracts and other agreements.
See Note 13 to the Financial Statements for discussion of guarantees.
COMMITMENTS AND CONTINGENCIES
See Note 13 to the Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to the Financial Statements for discussion of changes in accounting standards.
Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk that in the normal course of business we may experience a loss in value due to changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by several factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets.
We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management framework established and overseen by the Company's board of directors (Board) and the sustainability and risk committee of the Board, as applicable. Interest rate risk is managed centrally by our treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and portfolio valuation and reporting.
Commodity Price Risk
Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices.
In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions.
VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.
Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions) and (iii) historical estimates of volatility and correlation data. The table below details a VaR measure related to various portfolios of contracts.
VaR for Underlying Generation Assets and Energy-Related Contracts — This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level and an assumed holding period of 60 days. The forward period covered by this calculation includes the current and subsequent calendar year at the time of calculation.
|Year Ended December 31,|
|Month-end average VaR||$||234||$||263|
|Month-end high VaR||$||361||$||520|
|Month-end low VaR||$||164||$||103|
The VaR risk measures in 2020 were primarily comparable to the prior year. Month-end high VaR was lower in 2020 due to lower prices and a decrease in volatility in ERCOT as compared to the prior year.
Interest Rate Risk
The following table provides information concerning our financial instruments at December 31, 2020 and 2019 that are sensitive to changes in interest rates. Debt amounts consist of the Vistra Operations Credit Facilities. See Note 11 to the Financial Statements for further discussion of these financial instruments.
|Expected Maturity Date||2020|
|Long-term debt, including current maturities (a):|
|Variable rate debt amount||$||28||$||29||$||28||$||29||$||2,458||$||—||$||2,572||$||2,565||$||2,700||$||2,717|
|Average interest rate (b)||1.90||%||1.90||%||1.90||%||1.90||%||1.90||%||—||%||1.90||%||3.55||%|
|Debt swapped to fixed (c):|
|Average pay rate||3.76||%||3.76||%||4.18||%||4.77||%||4.77||%||4.77||%|
|Average receive rate||1.90||%||1.90||%||1.97||%||2.06||%||2.06||%||2.06||%|
(a)Unamortized premiums, discounts and debt issuance costs are excluded from the table.
(b)The weighted average interest rate presented is based on the rates in effect at December 31, 2020.
(c)Interest rate swaps have maturity dates through July 2026. Excludes $2.12 billion of debt swapped to variable that is matched against the terms of $2.12 billion of debt swapped to fixed that effectively fix the out-of-the-money position of such swaps (see Note 11 to the Financial Statements).
At December 31, 2020, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $6 million taking into account the interest rate swaps discussed in Note 11 to Financial Statements.
Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 16 to the Financial Statements for further discussion of this exposure.
Bankruptcies — We are party to (i) certain gas transportation agreements with PG&E and (ii) a long-term resource adequacy contract with PG&E in connection with the Moss Landing battery storage project, which was originally approved by the California Public Utilities Commission (CPUC) in November 2018. 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.
Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $1.282 billion at December 31, 2020.
At December 31, 2020, Retail segment credit exposure totaled $990 million, including $982 million of trade accounts receivable and $8 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables totaled $80 million, resulting in a net exposure of $910 million. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.
At December 31, 2020, aggregate Texas, East and Sunset segments credit exposure totaled $292 million including $163 million related to derivative assets and $129 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts.
Including collateral posted to us by counterparties, our net Texas, East and Sunset segments exposure was $281 million substantially all of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at December 31, 2020. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.
|Below investment grade or no rating||38||6||32|
Significant (i.e., 10% or greater) concentration of credit exposure exists with one counterparty, which represented an aggregate $85 million, or 30%, of the total net exposure. We view exposure to this counterparty to be within an acceptable level of risk tolerance due to the counterparty's credit ratings, which is rated as investment grade, the counterparty's market role and deemed creditworthiness and the importance of our business relationship with the counterparty. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us.
Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.
This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "may," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in this annual report on Form 10-K and the following important factors, among others, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:
•the actions and decisions of judicial and regulatory authorities;
•prohibitions and other restrictions on our operations due to the terms of our agreements;
•prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the MSHA and the CFTC, with respect to, among other things:
▪industry, market and rate structure;
▪purchased power and recovery of investments;
▪operations of nuclear generation facilities;
▪operations of fossil-fueled generation facilities;
▪operations of mines;
▪acquisition and disposal of assets and facilities;
▪development, construction and operation of facilities;
▪present or prospective wholesale and retail competition;
▪changes in federal, state and local tax laws, rates and policies, including additional regulation, interpretations, amendments, or technical corrections to the TCJA;
▪changes in and compliance with environmental and safety laws and policies, including the Coal Combustion Residuals Rule, National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and GHG and other climate change initiatives; and
▪clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;
•expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise negatively impact our financial results or stock price;
•legal and administrative proceedings and settlements;
•general industry trends;
•economic conditions, including the impact of any recession or economic downturn;
•investor sentiment relating to climate change and utilization of fossil fuels in connection with power generation could reduce demand for, or increase potential volatility in the market price of, our common stock;
•the severity, magnitude and duration of pandemics, including the COVID-19 pandemic, and the resulting effects on our results of operations, financial condition and cash flows;
•the severity, magnitude and duration of extreme weather events (including winter storm Uri), drought and limitations on access to water, and other weather conditions and natural phenomena, and the resulting effects on our results of operations, financial condition and cash flows;
•acts of sabotage, wars or terrorist or cybersecurity threats or activities;
•risk of contract performance claims by us or our counterparties, and risks of, or costs associated with, pursuing or defending such claims;
•our ability to collect trade receivables from counterparties in the amount or at the time expected, if at all;
•our ability to attract, retain and profitably serve customers;
•restrictions on competitive retail pricing or direct-selling businesses;
•adverse publicity associated with our retail products or direct selling businesses, including our ability to address the marketplace and regulators regarding our compliance with applicable laws;
•changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
•changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
•sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation and storage thereof;
•changes in the ability of vendors to provide or deliver commodities as needed;
•beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;
•the effects of, or changes to, market design and the power and capacity procurement processes in the markets in which we operate;
•changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;
•our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
•population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT, MISO and PJM;
•our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE;
•efforts to identify opportunities to reduce congestion and improve busbar power prices;
•access to adequate transmission facilities to meet changing demands;
•changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
•changes in operating expenses, liquidity needs and capital expenditures;
•commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets;
•access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;
•our ability to maintain prudent financial leverage and achieve our capital allocation objectives;
•our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations;
•our expectation that we will continue to pay a comparable cash dividend on a quarterly basis;
•our ability to implement and successfully execute upon\ our growth strategy, including the completion and integration of mergers, acquisitions and/or joint venture activity, the identification and completion of sales and divestitures activity, and the completion and commercialization of our other business development and construction projects;
•competition for new energy development and other business opportunities;
•inability of various counterparties to meet their obligations with respect to our financial instruments;
•counterparties' collateral demands and other factors affecting our liquidity position and financial condition;
•changes in technology (including large scale electricity storage) used by and services offered by us;
•changes in electricity transmission that allow additional power generation to compete with our generation assets;
•our ability to attract and retain qualified employees;
•significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur or changes in laws or regulations relating to independent contractor status;
•changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under ERISA;
•hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;
•the impact of our obligations under the TRA;
•our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations performance initiatives;
•our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation obligations and the impacts thereof;
•our ability to successfully complete the integration of businesses acquired by Vistra and our ability to successfully capture the full amount of projected operational and financial synergies relating to such transactions; and
•actions by credit rating agencies.
Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.
INDUSTRY AND MARKET INFORMATION
Certain industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of states in which we operate and NYMEX. We did not commission any of these publications, reports or other sources. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Industry publications, reports and other sources generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies, publications, reports and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this report involve risks and uncertainties and are subject to change based on various factors.
Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Vistra Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Vistra Corp. and its subsidiaries (the "Company") as of December 31, 2020 and 2019, the related consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of cash flows, and consolidated statement of changes in equity, for each of the three years in the period ended December 31, 2020, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2021, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Tax Receivable Agreement Obligation — Refer to Notes 1 and 8 to the financial statements
Critical Audit Matter Description
The Company has a tax receivable agreement (TRA) obligation that requires the Company to make annual payments to the TRA rights holders based on cash savings in income tax resulting from a step up in the tax basis of certain assets upon emergence from bankruptcy in 2016. The carrying value of the TRA obligation is based on the discounted amount of forecasted payments to the TRA rights holders. Determining the carrying value of the TRA obligation requires management to make significant estimates and assumptions in preparing its forecast of taxable income for a period of approximately 40 years. Changes to either the estimated timing or amount of expected TRA payments impact the carrying value of the obligation. As of December 31, 2020, the carrying value of the TRA obligation totaled $450 million.
Given the significant judgements made by management to estimate the TRA obligation, performing audit procedures to evaluate the reasonableness of management’s estimate and assumptions related to the estimated future taxable income required a high degree of auditor judgement and an increased extent of effort, including the need to involve our income tax specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the evaluation of estimated future taxable income included the following, among others:
•We tested the effectiveness of controls over management’s determination of the TRA obligation carrying amount, including controls over developing estimated future taxable income.
•With the assistance of our income tax specialists, we evaluated the following elements in testing management’s estimated future taxable income:
◦The application of tax laws and regulations
◦Future reversals of existing temporary differences, including the timing and amount of loss carryforwards
•We evaluated the reasonableness of management’s estimates of future taxable income by comparing the estimates to:
◦Historical taxable income
◦Internal communications to management and the Board of Directors
◦Forecasted information included in the Company's press releases as well as in analyst and industry reports for the Company
•We assessed the consistency of future taxable income with evidence obtained in other areas of the audit.
Fair Value Measurements — Level 3 Derivative Assets and Liabilities — Refer to Notes 1 and 15 to the financial statements
Critical Audit Matter Description
The Company has assets and liabilities whose fair values are based on complex proprietary models and unobservable inputs. These financial instruments can span a broad array of product types and generally include (1) electricity purchases and sales that include power and heat rate positions; (2) forward purchase contracts of congestion revenue rights and financial transmission rights; (3) physical electricity options, spread options, swaptions, and natural gas options; and (4) contracts for natural gas and coal. Under accounting principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3 derivative assets or liabilities. As of December 31, 2020, the fair value of the Level 3 derivative assets and liabilities totaled $205 million and $183 million, respectively.
Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of Level 3 derivative assets and liabilities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets and liabilities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling expertise.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the following, among others:
•We tested the effectiveness of controls over derivative asset and liability valuations, including controls related to price verification of illiquid price curves.
•We assessed to determine if management had consistently applied significant unobservable valuation assumptions.
•We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2020, to confirm our understanding of the types of instruments outstanding and performed a sensitivity analysis to understand the most significant assumptions impacting fair value.
•With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair value of a sample of Level 3 derivative instruments and compared our estimates to the Company's estimates.
Impairment of Long-Lived Assets—Refer to Notes 1 and 21 to the financial statements
Critical Audit Matter Description
The Company evaluates the carrying value of long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include declines in the forward prices of natural gas or electricity subsequent to the asset acquisition date, or an expectation that "more likely than not" a long-lived asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. Management determines if long-lived assets are impaired by comparing the forecasted undiscounted future cash flows to the carrying value. The forecasted undiscounted future cash flows include significant unobservable inputs such as forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures and forecasted delivered fuel prices. The carrying value of such assets is not recoverable if the forecasted undiscounted future cash flows are less than the carrying value. If the long-lived assets are not recoverable, fair value will be calculated based on a market participant view and a loss will be recorded based on the amount by which the carrying value exceeds the fair value. In determining the fair value of the long-lived assets, management uses a combination of a market approach valuation based on transactions of similar assets and an income approach valuation discounting the forecasted future cash flows. In 2020, management evaluated several of its power generation facilities for recoverability. Management concluded that three of the power generation facilities evaluated were not recoverable. The Company recorded impairment losses related to the three facilities of $324 million in 2020. As of December 31, 2020, the total carrying value of long-lived property, plant and equipment assets that are subject to evaluation for indicators of impairment was approximately $13.5 billion.
Given (1) management's evaluation of the recoverability of long-lived assets required management to make significant estimates and assumptions related to the development of forecasted undiscounted future cash flows, and (2) for those long-lived assets deemed impaired, the determination of fair value required management to make significant estimates and assumptions related to the discount rates to apply to the forecasted future cash flows, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists and fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the evaluation of management’s estimate of the forecasted future cash flows utilized in the evaluation of recoverability and determination of fair value of the long-lived assets deemed to be impaired included the following, among others:
•We tested the effectiveness of controls over management’s development of the assumptions used to estimate the forecasted future cash flows for the long-lived assets.
•We evaluated the reasonableness of management’s forecasted generation plant performance and forecasted capital expenditures assumptions by comparing the estimates to:
◦Historical generation volume output and capital expenditures for the respective long-lived assets
◦Internal communications to management and the Board of Directors
•With the assistance of our energy commodity fair value specialists:
◦We developed independent estimates of the forward natural gas and electricity prices and compared our estimates to the Company's estimates.
◦We evaluated the reasonableness of the Company's forward capacity prices, including the key assumptions underlying the development of those prices.
•With the assistance of our fair value specialists:
◦We developed a range of independent discount rates and compared those to the discount rates used by management in the income approach used to determine fair value of the impaired long-lived assets.
/s/ Deloitte & Touche LLP
February 26, 2021
We have served as the Company's auditor since 2002.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions of Dollars, Except Per Share Amounts)
|Year Ended December 31,|
|Operating revenues (Note 5)||$||11,443||$||11,809||$||9,144|
|Fuel, purchased power costs and delivery fees||(5,174)||(5,742)||(5,036)|
|Depreciation and amortization||(1,737)||(1,640)||(1,394)|
|Selling, general and administrative expenses||(1,035)||(904)||(926)|
|Impairment of long-lived assets||(356)||0||0|
|Other income (Note 21)||34||56||47|
|Other deductions (Note 21)||(42)||(15)||(5)|
|Interest expense and related charges (Note 21)||(630)||(797)||(572)|
|Impacts of Tax Receivable Agreement (Note 8)||5||(37)||(79)|
|Equity in earnings of unconsolidated investment (Note 21)||4||16||17|
|Income (loss) before income taxes||890||1,216||(101)|
|Income tax (expense) benefit (Note 7)||(266)||(290)||45|
|Net income (loss)||624||926||(56)|
|Net loss attributable to noncontrolling interest||12||2||2|
|Net income (loss) attributable to Vistra||$||636||$||928||$||(54)|
|Weighted average shares of common stock outstanding:|
|Net income (loss) per weighted average share of common stock outstanding:|
See Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
|Year Ended December 31,|
|Net income (loss)||$||624||$||926||$||(56)|
|Other comprehensive loss, net of tax effects:|
|Effects related to pension and other retirement benefit obligations (net of tax benefit of $5, $4 and $2)||(18)|