EDGAR 10-K Filing

Company CIK: 1692819
Filing Year: 2021
Filename: 1692819_10-K_2021_0001692819-21-000004.json

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ITEM 1. BUSINESS
Item 1.BUSINESS
References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.
Business
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.
Business Strategy
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.
Recent Developments
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.
Market Discussion
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.
Retail Markets
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.
Texas Segment
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 CCGT Natural Gas 7 7,838
ERCOT ST Coal 2 3,850
ERCOT CT or ST Natural Gas 7 3,455
ERCOT Nuclear Nuclear 1 2,300
ERCOT Solar/Battery Renewable 1 180
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.
East Segment
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)
PJM CCGT Natural Gas 8 6,081
PJM CT Natural Gas 4 1,346
PJM CT Fuel Oil 2 93
ISO-NE CCGT Natural Gas 6 3,361
NYISO CCGT Natural Gas 1 1,212
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.
West Segment
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)
CAISO CCGT Natural Gas 1 1,020
CAISO Battery Renewable 1 300
CAISO CT Fuel Oil 1 165
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.
Sunset Segment
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)
ERCOT ST Coal 1 650
MISO ST Coal 4 3,187
MISO CT Natural Gas 2 221
PJM ST Coal 3 3,428
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.
Wholesale Operations
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.
Seasonality
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
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.
Brand Value
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.
Safety
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.
Employee Benefits
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%.
Wellness
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.
Climate Change
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.
Air Emissions
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.
Ozone Designations
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.
Water
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.
Radioactive Waste
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.

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ITEM 1A. RISK FACTORS
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.
Operational Risks
•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;
•seasonality;
•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;
•regulatory developments;
•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.
Operational Risks
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B.UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
Item 2.PROPERTIES
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%
Baldwin Baldwin, IL MISO ST Coal 1,185 100%
Edwards Bartonville, IL MISO ST Coal 585 100%
Newton Newton, IL MISO ST Coal 615 100%
Joppa/EEI Joppa, IL MISO ST Coal 802 80%
Joppa CT 1-3 Joppa, IL MISO CT Natural Gas 165 100%
Joppa CT 4-5 Joppa, IL MISO CT Natural Gas 56 80%
Kincaid Kincaid, IL PJM ST Coal 1,108 100%
Miami Fort 7 & 8 North Bend, OH PJM ST Coal 1,020 100%
Zimmer Moscow, OH PJM ST Coal 1,300 100%
Total Sunset Segment 7,486
Total capacity 38,687
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(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.
Fuel Supply
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.

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
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.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6.SELECTED FINANCIAL DATA
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.
Business
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.
Operating Segments
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.
COVID-19 Pandemic
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.
Dividend Program
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.
Debt Activity
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.
Capacity Markets
PJM - Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year:
2020-2021 2021-2022
(average price per MW-day)
RTO zone (a) $ 88.32 $ 140.00
ComEd zone 188.12 195.55
MAAC zone 86.04 140.00
EMAAC zone 187.87 165.73
ATSI zone 76.53 171.33
PPL zone 86.04 140.00
____________
(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:
2020-2021 2021-2022 2022-2023
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:
Summer
2021 Winter
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:
Winter
2020 - 2021 Summer
2021 Winter
2021 - 2022 Summer
2022 Winter
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:
2020-2021 2021-2022 2022-2023 2023-2024
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.
2020-2021 2021-2022 2022-2023 2023-2024 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:
2020-2021
Price per MW-day $ 5.00
MISO capacity sales through planning year 2023-2024 are as follows:
2020-2021 2021-2022 2022-2023 2023-2024
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:
2021 2022
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:
2021 2022
Nuclear/Renewable/Coal Generation:
Texas 91 % 46 %
Sunset 98 % 57 %
Gas Generation:
Texas 76 % 16 %
East 92 % 23 %
West 99 % 9 %
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.
2021 2022
Texas:
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
East:
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
West:
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)
Sunset:
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.
Seasonality
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.
Purchase Accounting
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
Favorable (Unfavorable)
$ Change 2019 vs 2018
Favorable (Unfavorable)
$ Change
2020 2019 2018
Operating revenues $ 11,443 $ 11,809 $ 9,144 $ (366) $ 2,665
Fuel, purchased power costs and delivery fees (5,174) (5,742) (5,036) 568 (706)
Operating costs (1,622) (1,530) (1,297) (92) (233)
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) -
Operating income
1,519 1,993 491 (474) 1,502
Other income 34 56 47 (22) 9
Other deductions (42) (15) (5) (27) (10)
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
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra Consolidated
Operating revenues $ 8,270 $ 4,116 $ 2,415 $ 282 $ 1,252 $ 3 $ (4,895) $ 11,443
Fuel, purchased power costs and delivery fees (6,857) (1,078) (1,262) (168) (704) - 4,895 (5,174)
Operating costs (123) (727) (270) (30) (408) (63) (1) (1,622)
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
Other income 6 3 1 1 6 10 7 34
Other deductions 1 (12) (30) - 2 (2) (1) (42)
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
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra Consolidated
Operating revenues $ 6,872 $ 3,836 $ 2,790 $ 338 $ 1,602 $ 341 $ (3,970) $ 11,809
Fuel, purchased power costs and delivery fees (5,816) (1,283) (1,393) (187) (767) (267) 3,971 (5,742)
Operating costs (71) (691) (236) (27) (366) (138) (1) (1,530)
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
Other income - 28 - - 7 3 18 56
Other deductions - (8) (1) - - (5) (1) (15)
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
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra Consolidated
Operating revenues $ 5,597 $ 2,497 $ 1,895 $ 208 $ 1,183 $ 371 $ (2,607) $ 9,144
Fuel, purchased power costs and delivery fees (4,126) (1,461) (1,131) (134) (505) (286) 2,607 (5,036)
Operating costs (39) (661) (164) (17) (305) (109) (2) (1,297)
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
Other income 29 34 1 - - 2 (19) 47
Other deductions - (7) (1) - 1 (1) 3 (5)
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
Favorable (Unfavorable)
$ Change 2019 vs 2018
Favorable (Unfavorable)
$ Change
2020 2019 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
EBITDA 3,332 3,726 1,943 (394) 1,783
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)
Other, net 19 11 (7) 8 18
Adjusted EBITDA $ 3,685 $ 3,325 $ 2,760 $ 360 $ 565
____________
(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
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
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
EBITDA 622 2,302 769 59 (279) (79) (62) 3,332
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
Other, net 11 26 10 4 3 1 (36) 19
Adjusted EBITDA $ 983 $ 1,646 $ 849 $ 73 $ 242 $ (81) $ (27) $ 3,685
____________
(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
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
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
EBITDA 447 1,879 1,093 107 398 (109) (89) 3,726
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
Other, net 10 12 15 - 8 2 (36) 11
Adjusted EBITDA $ 807 $ 1,307 $ 925 $ 63 $ 308 $ (68) $ (17) $ 3,325
____________
(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
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
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
EBITDA 1,037 392 547 47 324 (62) (342) 1,943
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
Other, net (13) (1) 25 2 9 (4) (25) (7)
Adjusted EBITDA $ 845 $ 912 $ 680 $ 65 $ 341 $ (63) $ (20) $ 2,760
____________
(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)
Change
2020 2019
Operating revenues:
Revenues in ERCOT $ 5,880 $ 5,061 $ 819
Revenues in Northeast/Midwest 2,406 1,818 588
Amortization expense (5) (15) 10
Other revenues (11) 8 (19)
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)
Delivery fees (1,893) (1,629) (264)
Other costs (a) (69) (330) 261
Total fuel, purchased power costs and delivery fees $ (6,857) $ (5,816) $ (1,041)
Net income
$ 309 $ 134 $ 175
Adjusted EBITDA $ 983 $ 807 $ 176
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,
Texas East West Sunset
2020 2019 2020 2019 2020 2019 2020 2019
Operating revenues:
Electricity sales $ 896 $ 1,048 $ 833 $ 1,355 $ 289 $ 293 $ 883 $ 969
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)
Other revenues - - 2 (4) - 4 (20) (17)
Operating revenues 4,116 3,836 2,415 2,790 282 338 1,252 1,602
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
Adjusted EBITDA $ 1,646 $ 1,307 $ 849 $ 925 $ 73 $ 63 $ 242 $ 308
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
Nuclear facilities 19,480 19,305
Solar/Battery facilities 432 439
Capacity factors:
CCGT facilities 49.2 % 55.0 % 57.9 % 58.4 % 59.1 % 58.5 %
Lignite and coal facilities 77.1 % 72.8 % 47.1 % 54.1 %
Nuclear facilities 96.7 % 95.8 %
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,
2020 2019 2020 2019
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
Massachusetts Hub $ 26.57 $ 34.89
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
Texas East West Sunset
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)
Other (24) (19) 1 (1)
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,
Texas East West Sunset
2019 2018 2019 2018 2019 2018 2019 2018
Operating revenues:
Electricity sales $ 1,048 $ 1,162 $ 1,355 $ 990 $ 293 $ 193 $ 969 $ 769
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
Other revenues - (1) (4) (8) 4 - (17) (1)
Operating revenues 3,836 2,497 2,790 1,895 338 208 1,602 1,183
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
Adjusted EBITDA $ 1,307 $ 912 $ 925 $ 680 $ 63 $ 65 $ 308 $ 341
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
Nuclear facilities 19,305 20,416
Solar/Battery facilities 439 344
Capacity factors:
CCGT facilities 55.0 % 58.8 % 58.4 % 59.1 % 58.5 % 56.1 %
Lignite and coal facilities 72.8 % 77.8 % 54.1 % 63.4 %
Nuclear facilities 95.8 % 101.3 %
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,
2019 2018 2019 2018
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
Massachusetts Hub $ 34.89 $ 50.11
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
Texas East West Sunset
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
Other (7) (9) - -
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)
Change
2020 2019
Operating revenues $ 3 $ 341 $ (338)
Fuel, purchased power costs and delivery fees - (267) 267
Operating costs (63) (138) 75
Depreciation and amortization (22) - (22)
Selling, general and administrative expenses (27) (43) 16
Operating loss (109) (107) (2)
Other income 10 3 7
Other deductions (2) (5) 3
Net loss
$ (101) $ (109) $ 8
Adjusted EBITDA $ (81) $ (68) $ (13)
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,
2020 2019
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 year 1-3 years 4-5 years Excess of
5 years Total
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
Total $ 96 $ (59) $ (47) $ (65) $ (75)
FINANCIAL CONDITION
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,
2020 2019
Capital expenditures, including LTSA prepayments $ 770 $ 520
Nuclear fuel purchases 88 89
Growth and development expenditures 401 104
Capital expenditures 1,259 $ 713
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.
Debt Activity
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.
Available Liquidity
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.
Capital Expenditures
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.
Capitalization
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.
Financial Covenants
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.
Year Ended
December 31, 2020
Revenues $ 10,954
Operating income $ 1,592
Net income $ 678
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
Noncontrolling interest $ -
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.
Guarantees
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.
Risk Oversight
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,
2020 2019
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
Total Carrying
Amount 2020
Total Fair
Value 2019
Total Carrying
Amount 2019
Total Fair
Value
2021 2022 2023 2024 2025 There-after
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):
Notional amount $ - $ - $ 2,300 $ - $ - $ 2,300 $ 4,600 $ 4,600
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
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.
Exposure
Before Credit
Collateral Credit
Collateral Net
Exposure
Investment grade $ 254 $ 5 $ 249
Below investment grade or no rating 38 6 32
Totals
$ 292 $ 11 $ 281
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.
FORWARD-LOOKING STATEMENTS
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:
▪allowed prices;
▪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;
▪decommissioning costs;
▪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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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
Dallas, Texas
February 26, 2021
We have served as the Company's auditor since 2002.
VISTRA CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions of Dollars, Except Per Share Amounts)
Year Ended December 31,
2020 2019 2018
Operating revenues (Note 5) $ 11,443 $ 11,809 $ 9,144
Fuel, purchased power costs and delivery fees (5,174) (5,742) (5,036)
Operating costs (1,622) (1,530) (1,297)
Depreciation and amortization (1,737) (1,640) (1,394)
Selling, general and administrative expenses (1,035) (904) (926)
Impairment of long-lived assets (356) - -
Operating income 1,519 1,993 491
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:
Basic
488,668,263 494,146,268 504,954,371
Diluted
491,090,468 499,935,490 504,954,371
Net income (loss) per weighted average share of common stock outstanding:
Basic $ 1.30 $ 1.88 $ (0.11)
Diluted $ 1.30 $ 1.86 $ (0.11)
See Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
Year Ended December 31,
2020 2019 2018
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) (8) (6)
Adoption of new accounting standard - - 1
Total other comprehensive loss (18) (8) (5)
Comprehensive income (loss) 606 918 (61)
Comprehensive loss attributable to noncontrolling interest 12 2 2
Comprehensive income (loss) attributable to Vistra $ 618 $ 920 $ (59)
See Notes to the Consolidated Financial Statements.
VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
2020 2019 2018
Cash flows - operating activities:
Net income (loss) $ 624 $ 926 $ (56)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization 2,048 1,876 1,533
Deferred income tax expense (benefit), net 230 281 (62)
Impairment of long-lived assets (Note 4) 356 - -
Loss on disposal of investment in NELP (Note 21) 29 - -
Unrealized net (gain) loss from mark-to-market valuations of commodities (231) (696) 380
Unrealized net loss from mark-to-market valuations of interest rate swaps 155 220 5
Change in asset retirement obligation liability 7 (48) (27)
Asset retirement obligation accretion expense 43 53 50
Impacts of Tax Receivable Agreement (Note 8) (5) 37 79
Bad debt expense 110 82 55
Stock-based compensation 65 47 73
Other, net (22) (12) 37
Changes in operating assets and liabilities:
Accounts receivable - trade (33) (88) (207)
Inventories (59) (44) 61
Accounts payable - trade (40) (221) 90
Commodity and other derivative contractual assets and liabilities 27 98 (80)
Margin deposits, net (20) 170 (221)
Accrued interest (20) 80 (105)
Accrued taxes 22 (4) (64)
Accrued employee incentive 39 1 40
Tax Receivable Agreement payment (Note 8) - (2) (16)
Asset retirement obligation settlement (118) (121) (100)
Major plant outage deferral 2 (19) (22)
Other - net assets 219 (22) 73
Other - net liabilities (91) 142 (45)
Cash provided by operating activities 3,337 2,736 1,471
Cash flows - investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments (1,259) (713) (530)
Ambit acquisition (net of cash acquired) (Note 2) - (506) -
Crius acquisition (net of cash acquired) (Note 2) - (374) -
Cash acquired in the Merger (Note 2) - - 445
Proceeds from sales of nuclear decommissioning trust fund securities (Note 21) 433 431 252
Investments in nuclear decommissioning trust fund securities (Note 21) (455) (453) (274)
Proceeds from sales of environmental allowances 165 197 1
Purchases of environmental allowances (504) (322) (5)
Proceeds from sales of assets 24 6 7
VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
2020 2019 2018
Other, net 24 17 3
Cash used in investing activities (1,572) (1,717) (101)
Cash flows - financing activities:
Issuances of long-term debt (Note 11) - 6,507 1,000
Repayments/repurchases of debt (Note 11) (1,008) (7,109) (3,075)
Net borrowings/(payments) under accounts receivable securitization program (Note 10) (150) 111 339
Borrowings under Revolving Credit Facility (Note 11) 1,075 650 -
Repayments under Revolving Credit Facility (Note 11) (1,425) (300) -
Debt tender offer and other debt financing fees (Note 11) (17) (203) (236)
Stock repurchase (Note 14) - (656) (763)
Dividends paid to stockholders (Note 14) (266) (243) -
Other, net (5) 6 12
Cash used in financing activities (1,796) (1,237) (2,723)
Net change in cash, cash equivalents and restricted cash (31) (218) (1,353)
Cash, cash equivalents and restricted cash - beginning balance 475 693 2,046
Cash, cash equivalents and restricted cash - ending balance $ 444 $ 475 $ 693
See Notes to the Consolidated Financial Statements.
VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
December 31,
2020 2019
ASSETS
Current assets:
Cash and cash equivalents $ 406 $ 300
Restricted cash (Note 21) 19 147
Trade accounts receivable - net (Note 21) 1,279 1,365
Inventories (Note 21) 515 469
Commodity and other derivative contractual assets (Note 16) 748 1,333
Margin deposits related to commodity contracts 257 202
Prepaid expense and other current assets 205 298
Total current assets 3,429 4,114
Restricted cash (Note 21) 19 28
Investments (Note 21) 1,759 1,537
Investment in unconsolidated subsidiary (Note 21) - 124
Operating lease right-of-use assets (Note 12) 45 44
Property, plant and equipment - net (Note 21) 13,499 13,914
Goodwill (Note 6) 2,583 2,553
Identifiable intangible assets - net (Note 6) 2,446 2,748
Commodity and other derivative contractual assets (Note 16) 258 136
Accumulated deferred income taxes (Note 7) 838 1,066
Other noncurrent assets 332 352
Total assets $ 25,208 $ 26,616
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 11) $ - $ 350
Accounts receivable securitization program (Note 10) 300 450
Long-term debt due currently (Note 11) 95 277
Trade accounts payable 880 947
Commodity and other derivative contractual liabilities (Note 16) 789 1,529
Margin deposits related to commodity contracts 33 8
Accrued income taxes 16 1
Accrued taxes other than income 210 200
Accrued interest 131 151
Asset retirement obligations (Note 21) 103 141
Operating lease liabilities (Note 12) 8 14
Other current liabilities 471 506
Total current liabilities 3,036 4,574
Long-term debt, less amounts due currently (Note 11) 9,235 10,102
Operating lease liabilities (Note 12) 40 41
Commodity and other derivative contractual liabilities (Note 16) 624 396
Accumulated deferred income taxes (Note 7) 1 2
Tax Receivable Agreement obligation (Note 8) 447 455
Asset retirement obligations (Note 21) 2,333 2,097
Other noncurrent liabilities and deferred credits (Note 21) 1,131 989
Total liabilities 16,847 18,656
VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
December 31,
2020 2019
Commitments and Contingencies (Note 13)
Total equity (Note 14):
Common stock (par value - $0.01; number of shares authorized - 1,800,000,000)
(shares outstanding: December 31, 2020 - 489,305,888; December 31, 2019 - 487,698,111)
5 5
Treasury stock, at cost (shares: December 31, 2020 - 41,043,224; December 31, 2019 - 41,043,224)
(973) (973)
Additional paid-in-capital
9,786 9,721
Retained deficit
(399) (764)
Accumulated other comprehensive loss (48) (30)
Stockholders' equity
8,371 7,959
Noncontrolling interest in subsidiary
(10) 1
Total equity
8,361 7,960
Total liabilities and equity $ 25,208 $ 26,616
See Notes to the Consolidated Financial Statements.
VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)
Common Stock Treasury Stock Additional Paid-In Capital Retained Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity
Balances at December 31, 2017 $ 4 $ - $ 7,765 $ (1,410) $ (17) $ 6,342 $ - $ 6,342
Stock and stock compensation awards issued in connection with the Merger 1 - 1,901 - - 1,902 - 1,902
Stock repurchases - (778) - - - (778) - (778)
Effects of stock-based compensation - - 72 - - 72 - 72
Tangible equity units acquired - - 369 - - 369 - 369
Warrants acquired - - 2 - - 2 - 2
Net loss - - - (54) - (54) (2) (56)
Adoption of new accounting standards - - - 16 1 17 - 17
Pension and OPEB liability - change in funded status - - - - (6) (6) - (6)
Investment by noncontrolling interest - - - - - - 6 6
Other - - (2) (1) - (3) - (3)
Balances at December 31, 2018 $ 5 $ (778) $ 10,107 $ (1,449) $ (22) $ 7,863 $ 4 $ 7,867
Stock repurchases - (641) - - - (641) - (641)
Shares issued for tangible equity unit contracts - 446 (446) - - - - -
Effects of stock-based compensation - - 62 - - 62 - 62
Net income (loss) - - - 928 - 928 (2) 926
Dividends declared on common stock - - - (243) - (243) - (243)
Adoption of new accounting standard - - - (2) - (2) - (2)
Pension and OPEB liability - change in funded status - - - - (8) (8) - (8)
Other - - (2) 2 - - (1) (1)
Balances at December 31, 2019 $ 5 $ (973) $ 9,721 $ (764) $ (30) $ 7,959 $ 1 $ 7,960
Effects of stock-based compensation - - 65 - - 65 - 65
Net income (loss) - - - 636 - 636 (12) 624
Dividends declared on common stock - - - (266) - (266) - (266)
Adoption of new accounting standard - - - (4) - (4) - (4)
Pension and OPEB liability - change in funded status - - - - (18) (18) - (18)
Investment by noncontrolling interest - 1 1
Other - - - (1) - (1) - (1)
Balances at December 31, 2020 $ 5 $ (973) $ 9,786 $ (399) $ (48) $ 8,371 $ (10) $ 8,361
See Notes to the Consolidated Financial Statements.
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.
Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including 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. (Vistra) to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect or integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business powering the communities we serve with safe, reliable power.
Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. Management believes that the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The following is a summary of the updated segments:
•The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments. As we announced significant plant closures in the third quarter of 2020, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.
•The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes operations in PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.
•The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporate and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 3), the Company expects to expand its operations in the West segment.
In addition, the ERCOT segment was renamed the Texas segment. There were no changes to the Retail and Asset Closure segments. All historical segment results within these consolidated financial statements have been recast to be in alignment with our new segmentation. See Note 20 for further information concerning reportable business segments.
Ambit Transaction
On November 1, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of Ambit (Ambit Transaction). Because the Ambit Transaction closed on November 1, 2019, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Ambit and its subsidiaries prior to November 1, 2019. See Note 2 for a summary of the Ambit Transaction.
Crius Transaction
On July 15, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly owned the operating business of Crius (Crius Transaction). Because the Crius Transaction closed on July 15, 2019, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Crius and its subsidiaries prior to July 15, 2019. See Note 2 for a summary of the Crius Transaction.
Dynegy Merger Transaction
On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation. Because the Merger closed on April 9, 2018, Vistra's consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy prior to April 9, 2018. See Note 2 for a summary of the Merger transaction and business combination accounting.
COVID-19 Pandemic
In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and U.S. Government declared the COVID-19 outbreak a national emergency. The U.S. government has deemed electricity generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency. As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations.
The Company's consolidated financial statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impact of COVID-19 on the assumptions and estimates used and determined that there have been no material adverse impacts on the Company's results of operations for the year ended December 31, 2020.
In response to the global pandemic related to COVID-19, the CARES Act was signed into law on March 27, 2020. See Note 7 for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.
February 2021 Weather Event
In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. At the time we issued these financial statements, we expect the impact of the weather event to be a material loss that will be reflected in our first quarter 2021 results of operations. However, uncertainty exists with respect to the financial impact of the weather event due in part to outstanding pricing and settlement data from ERCOT, the outcome of potential litigation arising from the event, or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain (i.e. fuel supply, wholesale pricing of generation, or allocating the financial impacts of market-wide load shed ratably across all retail market participants), that is currently being considered or may be considered by any such parties.
Basis of Presentation
The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2019 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of derivative contracts rather than collateral. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 15 and 16 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. At December 31, 2020 and 2019, there were no derivative positions accounted for as cash flow or fair value hedges.
We report commodity hedging and trading results as revenue, fuel expense or purchased power in the consolidated statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges and trading activities are primarily reported as revenue. Physical or financial hedges for coal, diesel or uranium, along with physical natural gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the consolidated statements of operations in interest expense.
Revenue Recognition
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts. See Note 5 for detailed descriptions of revenue from contracts with customers. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.
Advertising Expense
We expense advertising costs as incurred and include them within SG&A expenses. Advertising expenses totaled $43 million, $49 million and $46 million for the year ended December 31, 2020, 2019 and 2018, respectively.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 21 for details of impairments of long-lived assets recorded in 2020.
Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 6 for details of intangible assets with finite lives, including discussion of fair value determinations.
Goodwill and Intangible Assets with Indefinite Lives
As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill. We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See Note 6 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations.
Nuclear Fuel
Nuclear fuel is capitalized and reported as a component of our property, plant and equipment in our consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs and delivery fees in our consolidated statements of operations.
Major Maintenance Costs
Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in our consolidated statements of operations.
Defined Benefit Pension Plans and OPEB Plans
On the Merger Date, Vistra assumed the pension and OPEB plans that Dynegy had provided to certain of its eligible employees and retirees. The excess of the benefit obligations over the fair value of plan assets was recognized as a liability. See Note 2 for additional information regarding the Merger.
Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employee from the company. Pension benefits are offered to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates.
See Note 17 for additional information regarding pension and OPEB plans.
Stock-Based Compensation
Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. The fair value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model. Forfeitures are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. See Note 18 for additional information regarding stock-based compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as "pass through" items on the consolidated balance sheets with no effect on the consolidated statements of operations (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in our consolidated statements of operations).
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in our consolidated statements of operations.
Income Taxes
On the Merger Date, Vistra and Dynegy effected a merger transaction that for tax purposes was treated as a tax-free reorganization in which Vistra survived as the parent entity. In general, all of Dynegy's tax basis and attributes were transferred to Vistra, including approximately $4.5 billion of utilizable NOLs and refundable alternative minimum tax (AMT) tax credits.
Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of our solar and battery storage facilities of zero, $2 million and $78 million and a corresponding increase in the deferred tax assets in 2020, 2019 and 2018, respectively.
Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. See Note 7.
We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 7.
Tax Receivable Agreement (TRA)
The Company accounts for its obligations under the TRA as a liability in our consolidated balance sheets (see Note 8). The carrying value of the TRA obligation represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business.
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the estimated amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. These changes are included on our consolidated statements of operations under the heading of Impacts of Tax Receivable Agreement.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 13 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered cash equivalents.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. See Note 21 for more details regarding restricted cash.
Property, Plant and Equipment
Property, plant and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed (see Notes 2 and 3). Significant improvements or additions to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 21.
Depreciation of our property, plant and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 21.
Asset Retirement Obligations (ARO)
A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which capitalized costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 21.
Regulatory Asset or Liability
The costs to ultimately decommission the Comanche Peak nuclear power plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in our consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits.
Inventories
Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (calculated on a weighted average basis) or net realizable value. We expect to recover the value of inventory costs in the normal course of business. See Note 21.
Investments
Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 21 for discussion of these and other investments.
Unconsolidated Investments
We use the equity method of accounting for investments in affiliates over which we exercise significant influence. Our share of net income from these affiliates is recorded to equity in earnings of unconsolidated investment in the consolidated statements of operations. See Note 21.
Noncontrolling Interest
Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. EEI is our consolidated subsidiary that owns a coal facility in Joppa, Illinois. This noncontrolling interest is classified as a component of equity separate from stockholders' equity in the consolidated balance sheets.
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capital. See Note 14.
Leases
At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration.
Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in operating lease ROU assets, operating lease liabilities (current) and operating lease liabilities (noncurrent) on our consolidated balance sheet. Finance leases are included in property, plant and equipment, other current liabilities and other noncurrent liabilities and deferred credits on our consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842 to not separate lease and non-lease components for a majority of our lease asset classes.
Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.
We also present lessor sublease income on a net basis against the related lessee lease expense.
Adoption of Accounting Standards Issued Prior to 2020
Simplifying the Accounting for Income Taxes - In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2019-12, Simplifying the Accounting for Income Taxes (Topic 740). The ASU enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. We adopted all provisions of this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.
Changes to the Disclosure Requirements for Fair Value Measurement - In August 2018, the FASB issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement. The ASU removes disclosure requirements for (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of transfers between levels and (c) the valuation processes for Level 3. The ASU requires new disclosures around (a) the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. We adopted this ASU in the first quarter of 2020, and the updated disclosures are included in Note 15.
Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract - In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The ASU requires a customer in a cloud hosting arrangement that is a service contract to determine which implementation costs to capitalize and which costs to expense based on the project stage of the implementation. The ASU also requires the customer to expense the capitalized implementation costs over the term of the hosting arrangement. The customer is required to apply the existing impairment and abandonment guidance on the capitalized implementation costs. We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.
Financial Instruments-Credit Losses - In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. The ASU requires organizations to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.
Leases - On January 1, 2019, we adopted Accounting Standards Update (ASU) 2016-02, Leases (Topic 842) and all related amendments (new lease standard) using the modified retrospective method with the cumulative-effect adjustment to the opening balance of retained deficit for all contracts outstanding at the time of adoption. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new lease standard to be immaterial to our net income on an ongoing basis. The impact of adopting the new lease standard primarily relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases. Under the new lease standard, each ROU asset will be amortized over the lease term and liability settled at the end of the lease term. We recognized the effect of initially applying the new lease standard by recording ROU assets of $85 million and lease liabilities of $123 million in our consolidated balance sheet. See Note 12 for the disclosures required by the new lease standard.
Changes to the Disclosure Requirements for Defined Benefit Plans - In August 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans. The ASU removes disclosure requirements for (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year, (b) related party disclosures about the amount of future annual benefits covered by insurance and annuity contracts and significant transactions between the employer or related parties and the plan and (c) the effects of a one-percentage-point change in assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic benefit costs and benefit obligation for postretirement health care benefits. The ASU requires new disclosures for (a) the weighted-average interest crediting rates for cash balance plans and other plans with promised interest crediting rates and (b) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. We adopted this ASU in the fourth quarter of 2018, and the updated disclosures are included in Note 17.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The ASU permits the reclassification of income tax effects of the TCJA on items within accumulated other comprehensive income (AOCI) to retained earnings. We adopted this ASU in the fourth quarter of 2018, and the impact was additional tax expense to AOCI of $1 million with the offset to retained deficit (see Note 7).
Revenue from Contracts with Customers - On January 1, 2018, we adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) and all related amendments (new revenue standard) using the modified retrospective method for all contracts outstanding at the time of adoption. We recognized the cumulative effect of initially applying the revenue standard as an adjustment to the opening balance of retained deficit. The impact of the adoption of the revenue standard was immaterial and we expect the adoption to continue to be immaterial to our net income on an ongoing basis. Our retail energy charges and wholesale generation, capacity and contract revenues will continue to be recognized when electricity and other services are delivered to our customers. The impact of adopting the revenue standard primarily relates to the deferral of acquisition costs associated with retail contracts with customers that were previously expensed as incurred. Under the revenue standard, these amounts are capitalized and amortized over the expected life of the customer.
Adoption of Accounting Standards Issued in 2020
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The ASU provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022. The adoption of this guidance did not have a material impact on our financial statements.
In March 2020, the SEC amended Rule 3-10 of Regulation S-X regarding financial disclosure requirements for registered debt offerings involving subsidiaries as either issuers or guarantors and affiliates whose securities are pledged as collateral. This new guidance narrows the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamlines the alternative disclosures required in lieu of those statements. This rule is effective January 4, 2021 with earlier adoption permitted. We elected to adopt this rule in the first quarter of 2020. Accordingly, summarized financial information has been presented only for the issuer and guarantors of the Company's registered debt securities, and the location of the required disclosures has been moved outside the Notes to the Consolidated Financial Statements and is provided in Part II, Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations under Financial Condition - Guarantor Summary Financial Information. In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) - Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762, to reflect the SEC's new disclosure rules on guaranteed debt securities adopted by the Company.
2.ACQUISITIONS, MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING
Ambit Transaction
On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra, completed the Ambit Transaction. Ambit is an energy retailer selling both electricity and natural gas products to residential and small business customers in 17 states. Vistra funded the purchase price of $555 million (including cash acquired and net working capital) using cash on hand. All of Ambit's outstanding debt was repaid from the purchase price at closing and not assumed by Vistra.
Crius Transaction
On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius. Crius is an energy retailer selling both electricity and natural gas products to residential and small business customers in 19 states. Vistra funded the purchase price of $400 million (including $382 million for outstanding trust units) using cash on hand. In addition, Vistra assumed $140 million of outstanding debt and acquired $26 million of cash at the closing of the Crius Transaction. See Note 11 for discussion of debt assumed in the Crius Transaction.
Ambit and Crius Business Combination Accounting
We believe the Ambit Transaction has (i) augmented Vistra's existing retail marketing capabilities with additional direct selling capability and a proprietary technology platform, (ii) reduced risk and aided expansion into higher margin channels by improving Vistra's match of its generation to load profile due to a high degree of overlap of Vistra's generation fleet with Ambit's approximately 11 TWh of annual load, primarily in ERCOT and PJM and (iii) enhanced the integrated value proposition through collateral and transaction efficiencies, particularly via Ambit's retail electric portfolio.
We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving Vistra's match of its generation to load profile due to a high degree of overlap of Vistra's generation fleet with Crius' approximately 10 TWh of annual electricity load, (ii) established a platform for growth by leveraging Vistra's existing retail marketing capabilities and Crius' experienced team and (iii) enhanced the integrated value proposition through collateral and transaction efficiencies, particularly via Crius' retail electric portfolio.
Each of the Ambit Transaction and Crius Transaction, respectively, was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Ambit Acquisition Date and Crius Acquisition Date, respectively. The combined results of operations are reported in our consolidated financial statements beginning as of the respective Ambit Acquisition Date and Crius Acquisition Date. A summary of the techniques used to estimate the fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 15), is listed below:
•Working capital was valued using available market information (Level 2).
•Acquired derivatives were valued using the methods described in Note 15 (Level 2 or Level 3).
•Acquired retail customer relationship was valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).
•Crius' long-term debt was valued using a market approach (Level 2).
The following table summarizes the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Ambit Transaction and Crius Transaction, respectively, as of the Ambit Acquisition Date and Crius Acquisition Date, respectively. The Ambit Transaction purchase price was $555 million (including cash acquired and net working capital) and the Crius Transaction purchase price was $400 million. The final purchase price allocations were completed in the second quarter of 2020 for the Crius Transaction and the third quarter of 2020 for the Ambit Transaction.
Ambit Transaction and Crius Transactions Final Purchase Price Allocations
Ambit Transaction Crius Transaction
Final
Purchase Price
Allocation Measurement Period Adjustments recorded through September 30, 2020 Final
Purchase Price
Allocation Measurement Period Adjustments recorded through June 30, 2020
Cash and cash equivalents $ 49 $ - $ 26 $ -
Net working capital 32 3 (9) (42)
Accumulated deferred income taxes - - - (36)
Identifiable intangible assets 218 (45) 317 23
Goodwill 258 44 243 38
Commodity and other derivative contractual assets 23 - 18 -
Other noncurrent assets 13 - 17 (3)
Total assets acquired 593 2 612 (20)
Identifiable intangible liabilities - - 2 (34)
Long-term debt, including amounts due currently - - 140 -
Commodity and other derivative contractual liabilities 28 - 40 -
Accumulated deferred income taxes - - 14 14
Other noncurrent liabilities and deferred credits 10 2 16 -
Total liabilities assumed 38 2 212 (20)
Identifiable net assets acquired $ 555 $ - $ 400 $ -
Acquisition costs incurred in the Ambit Transaction and Crius Transaction totaled $1 million and $2 million, respectively. For the Ambit Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the Ambit Transaction totaling $193 million and $2 million, respectively. For the Crius Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the Crius Transaction totaling $453 million and zero, respectively. The net income acquired in the Ambit Transaction and Crius Transaction include intangible amortization and transition related expenses.
Ambit and Crius Transaction Unaudited Pro Forma Financial Information - The following unaudited consolidated pro forma financial information for the years ended December 31, 2019 and 2018 assumes that the Ambit and Crius Transactions occurred on January 1, 2018 (i.e., represents our results for the years ended December 31, 2019 and 2018 plus the results for either Ambit Transaction or Crius Transaction for the period not owned by us, respectively). The unaudited consolidated pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Ambit Transaction and Crius Transaction been completed on January 1, 2018, nor is the unaudited consolidated pro forma financial information indicative of future results of operations, which may differ materially from the consolidated pro forma financial information presented here.
Ambit Transaction Crius Transaction
Year Ended December 31, Year Ended December 31,
2019 2018 2019 2018
Revenues $ 12,931 $ 10,446 $ 12,373 $ 10,379
Net income (loss) (a) $ 949 $ (95) $ 876 $ (43)
Net income (loss) attributable to Vistra $ 951 $ (93) $ 878 $ (41)
Net income (loss) attributable to Vistra per weighted average share of common stock outstanding - basic $ 1.92 $ (0.18) $ 1.78 $ (0.08)
Net income (loss) attributable to Vistra per weighted average share of common stock outstanding - diluted $ 1.90 $ (0.18) $ 1.76 $ (0.08)
__________
(a)Decrease in pro forma net income compared to consolidated net income is driven by unrealized losses on hedging activities of Crius and amortization of intangible assets.
The consolidated unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired and the related impacts on tax expense.
Dynegy Merger Transaction
On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation. The Merger was intended to qualify as a tax-free reorganization under the IRC, so that none of Vistra, Dynegy or any of the Dynegy stockholders would recognize any gain or loss in the transaction, except that Dynegy stockholders could recognize a gain or loss with respect to cash received in lieu of fractional shares of Vistra's common stock. Vistra is the acquirer for both federal tax and accounting purposes.
On the Merger Date, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares owned by Vistra or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, was automatically converted into 0.652 shares of common stock, par value $0.01 per share, of Vistra (the Exchange Ratio), except that cash was paid in lieu of fractional shares, which resulted in Vistra issuing 94,409,573 shares of Vistra common stock to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units and warrants. The total number of Vistra shares outstanding at the close of the Merger was 522,932,453 shares. Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra's common stock, after giving effect to the Exchange Ratio.
Dynegy Business Combination Accounting
We believe the Merger has provided and continues to provide significant strategic benefits and opportunities to Vistra, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flows. The Merger was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in our consolidated financial statements beginning as of the Merger Date. A summary of the techniques used to estimate the fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 15), is listed below:
•Working capital was valued using available market information (Level 2).
•Acquired property, plant and equipment was valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
•Acquired derivatives were valued using the methods described in Note 15 (Level 1, Level 2 or Level 3).
•Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference discounted to present value and recorded as either an intangible asset or liability.
•Long-term debt was valued using a market approach (Level 2).
•AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).
The following table summarizes the consideration paid and the final allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date. Based on the opening price of Vistra common stock on the Merger Date, the purchase price was approximately $2.3 billion. During the three months ended March 31, 2019, the purchase price allocation was completed. During the period from April 9, 2018 through March 31, 2019, we updated the initial purchase price allocation with final valuations by increasing property, plant and equipment by $173 million, decreasing intangible assets by $36 million, increasing goodwill by $175 million, decreasing accounts receivable, inventory, prepaid expenses and other current assets by $10 million, increasing accumulated deferred tax asset by $127 million, decreasing other noncurrent assets by $113 million, increasing trade accounts payable and other current liabilities by $89 million, increasing other noncurrent liabilities by $177 million, increasing asset retirement obligations, including amounts due currently by $56 million as well as other minor adjustments. The valuation revisions were a result of updated inputs used in determining the fair value of the acquired assets and liabilities.
Dynegy shares outstanding as of April 9, 2018 (in millions) 144.8
Exchange Ratio 0.652
Vistra shares issued for Dynegy shares outstanding (in millions) 94.4
Opening price of Vistra common stock on April 9, 2018 $ 19.87
Purchase price for common stock $ 1,876
Fair value of equity component of tangible equity units 369
Fair value of outstanding stock compensation awards attributable to pre-combination service 26
Fair value of outstanding warrants 2
Total purchase price $ 2,273
Dynegy Merger Final Purchase Price Allocation
Cash and cash equivalents $ 445
Trade accounts receivables, inventories, prepaid expenses and other current assets 853
Property, plant and equipment 10,535
Accumulated deferred income taxes 518
Identifiable intangible assets 351
Goodwill 175
Other noncurrent assets 419
Total assets acquired 13,296
Trade accounts payable and other current liabilities 733
Commodity and other derivative contractual assets and liabilities, net 422
Asset retirement obligations, including amounts due currently 475
Long-term debt, including amounts due currently 8,919
Other noncurrent liabilities 469
Total liabilities assumed 11,018
Identifiable net assets acquired 2,278
Noncontrolling interest in subsidiary 5
Total purchase price $ 2,273
Acquisition costs incurred in the Merger totaled less than $1 million and $25 million for the years ended December 31, 2019 and 2018, respectively. For the period from the Merger Date through December 31, 2018, our consolidated statements of operations include revenues and net income (loss) acquired in the Merger totaling $3.902 billion and $224 million respectively.
Dynegy Merger Unaudited Pro Forma Financial Information - The following unaudited pro forma financial information for the year ended December 31, 2018 assumes that the Merger occurred on January 1, 2018. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Merger been completed on January 1, 2018, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.
Year Ended December 31, 2018
Revenues $ 10,595
Net loss $ (268)
Net loss attributable to Vistra $ (265)
Net loss attributable to Vistra per weighted average share of common stock outstanding - basic $ (0.52)
Net loss attributable to Vistra per weighted average share of common stock outstanding - diluted $ (0.52)
The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Merger, effects of the Merger on tax expense (benefit), changes in the expected impacts of the tax receivable agreement due to the Merger, and other related adjustments.
3.ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES
Texas Segment Solar Generation and Energy Storage Projects
In September 2020, we announced the planned development of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. Estimated commercial operation dates for these facilities range from Summer 2021 to Fall 2022.
Upton 2 Phase I - In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas (Upton 2). As part of this project, we entered into a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. We spent approximately $231 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights. The facility began test operations in March 2018 and commercial operations began in June 2018.
Upton 2 Phase II - In 2018, we completed the construction of our first battery energy storage system (ESS). In October 2018, we were awarded a $1 million grant from the TCEQ for our battery ESS at our Upton 2 solar facility. The grant is part of the Texas Emissions Reduction Plan. The 10 MW lithium-ion ESS captures excess solar energy produced during the day and releases the energy in late afternoon and early evening, when demand is highest. The Upton 2 Phase II battery ESS became operational in December 2018.
West Segment Energy Storage Projects
Oakland - In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California. In April 2020, the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E). The contract was amended to increase the capacity of the planned development to a 36.25 MW battery ESS. In April 2020, the concurrent local area reliability service agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed and sent to the California Public Utilities Commission (CPUC) for approval, which is expected prior to the second quarter of 2021. The battery ESS project is expected to enter commercial operations by January 2022.
Moss Landing - In June 2018, we announced that, subject to approval by the CPUC, we would enter into a 20-year resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California (Moss Landing Phase I). PG&E filed its application with the CPUC in June 2018 and the CPUC approved the resource adequacy contract in November 2018. At December 31, 2020, we had accumulated approximately $370 million in construction work-in-process for Moss Landing Phase I. Under the contract, PG&E will pay us a fixed monthly resource adequacy payment, while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. Moss Landing Phase I began test operations in December 2020 and is expected to be fully operational by April 2021. PG&E filed for Chapter 11 bankruptcy protection in January 2019. In November 2019, the bankruptcy court approved PG&E's motion requesting approval of the assumption of the resource adequacy contract subject to the CPUC approving the terms of an amendment to the resource adequacy contract, and the CPUC approved the terms of the amendment in January 2020. PG&E emerged from bankruptcy protection in July 2020.
In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10-year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II). PG&E filed its application with the CPUC in May 2020 and the CPUC approved the resource adequacy contract in August 2020. At December 31, 2020, we had accumulated approximately $29 million in construction work-in-process for Moss Landing Phase II. We anticipate Moss Landing Phase II will commence commercial operations in the third quarter of 2021.
4.RETIREMENT OF GENERATION FACILITIES
2020 Announcements
In December 2020, we announced our intention to retire two natural gas facilities in Texas due to their age, cost profile and small scale, as well as low power prices, limited operational windows and substantial costs to repair, maintain and upgrade the facilities.
Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Dates Units Retired or
Expected Retirement Date
Wharton Boling, TX ERCOT Natural Gas 83 November 30, 2020
Trinidad Trinidad, TX ERCOT Natural Gas 244 By April 30, 2021
Total 327
In September 2020 and December 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 13), and in furtherance of our efforts to significantly reduce our carbon footprint. Expected plant retirement expenses of $43 million, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our Sunset segment. Operational results for plants with planned retirements are included in our Sunset segment beginning in the quarter when a retirement plan is announced. See Note 21 for discussion of impairments recorded in connection with these announcements.
Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Expected Retirement Date (a)
Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2025
Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027
Joppa Joppa, IL MISO Coal 802 By the end of 2025
Joppa Joppa, IL MISO Natural Gas 221 By the end of 2025
Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027
Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027
Newton Newton, IL MISO/PJM Coal 615 By the end of 2027
Zimmer Moscow, OH PJM Coal 1,300 By the end of 2027
Total 6,901
____________
(a)Generation facilities may retire earlier than expected dates if economic or other conditions dictate.
2019 Announcements
In September 2019, we announced the settlement of a lawsuit alleging violations of opacity and particulate matter limits at our Edwards facility in Bartonville, Illinois. As part of the settlement, which was approved by the U.S. District Court for the Central District of Illinois in November 2019, we will retire the Edwards facility by the end of 2022 (see Note 13). In August 2019, we announced the planned retirement of four additional power plants in Illinois with a total installed nameplate generation capacity of 2,068 MW. We retired these units due to changes in the Illinois multi-pollutant standard rule (MPS rule) that require us to retire approximately 2,000 MW of generation capacity (see Note 13). In light of the provisions of the Federal Power Act and the FERC regulations thereunder, the affected subsidiaries of Vistra identified the retired units by analyzing the economics of each of our Illinois plants and designating the least economic units for retirement. Expected plant retirement expenses of $47 million, driven by severance costs, were accrued in the year ended December 31, 2019 and were included primarily in operating costs of our Asset Closure segment. In August 2019, we remeasured our pension and OPEB plans resulting in an increase to the benefit obligation liability of $21 million, pretax other comprehensive loss of $18 million and curtailment expense of $3 million recognized as other deductions in our consolidated statements of operations. The following table details the units in Illinois totaling 2,653 MW that have been or will be retired. Operational results for the four retired plants identified below are included in the Asset Closure segment, which is engaged in the decommissioning and reclamation of retired plants and mines. Operational results for the Edwards facility are included in the Sunset segment.
Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Dates Units Retired or
Expected Retirement Date
Coffeen Coffeen, IL MISO Coal 915 November 1, 2019
Duck Creek Canton, IL MISO Coal 425 December 15, 2019
Havana Havana, IL MISO Coal 434 November 1, 2019
Hennepin Hennepin, IL MISO Coal 294 November 1, 2019
Edwards Bartonville, IL MISO Coal 585 By the end of 2022
Total 2,653
2018 Announcements
In August 2018, we filed a notice of suspension of operation with PJM and other mandatory regulatory notifications related to the retirement of our 51 MW Northeastern Power Company waste coal facility in McAdoo, Pennsylvania (Northeastern Facility). We decided to retire the Northeastern Facility due to its uneconomic operations and financial outlook. Following the receipt of regulatory approvals, the Northeastern Facility was retired in October 2018. The decision to retire the Northeastern Facility did not result in a material impact to the financial statements, and the operational results of the Northeastern Facility are included in our Asset Closure segment.
Two of our non-operated, jointly held power plants acquired in the Merger, for which our proportional generation capacity was 883 MW, were retired in May 2018. These units were retired as previously scheduled. No gain or loss was recorded in conjunction with the retirement of these units, and the operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.
Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Ownership Interest Date Units Retired
Killen Manchester, Ohio PJM Coal 204 33% May 31, 2018
Stuart Aberdeen, Ohio PJM Coal 679 39% May 24, 2018
Total
In January and February 2018, we retired three power plants in Texas with a total installed nameplate generation capacity of 4,167 MW. We decided to retire these units because they were projected to be uneconomic based on then current market conditions and would have faced significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement. Expected retirement expenses were accrued in the third and fourth quarter of 2017 and, as a result, no retirement expenses were recorded related to these facilities in the year ended December 31, 2018. The operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.
Name Location (all in the state of Texas) ISO/RTO Fuel Type Installed Nameplate Generation Capacity (MW) Date Units Retired
Monticello Titus County ERCOT Lignite/Coal 1,880 January 4, 2018
Sandow Milam County ERCOT Lignite 1,137 January 11, 2018
Big Brown Freestone County ERCOT Lignite/Coal 1,150 February 12, 2018
Total
4,167
5.REVENUE
The following tables disaggregate our revenue by major source:
Year Ended December 31, 2020
Retail Texas East West Sunset Asset Closure Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 5,813 $ - $ - $ - $ - $ - $ - $ 5,813
Retail energy charge in Northeast/Midwest 2,406 - - - - - - 2,406
Wholesale generation revenue from ISO/RTO - 475 310 124 473 1 - 1,383
Capacity revenue from ISO/RTO (a) - - (52) - 164 - - 112
Revenue from other wholesale contracts - 226 668 54 187 1 - 1,136
Total revenue from contracts with customers 8,219 701 926 178 824 2 - 10,850
Other revenues:
Intangible amortization (5) - 2 - (21) - - (24)
Hedging and other revenues (b) 56 416 (108) 101 151 1 - 617
Affiliate sales - 2,999 1,595 3 298 - (4,895) -
Total other revenues 51 3,415 1,489 104 428 1 (4,895) 593
Total revenues $ 8,270 $ 4,116 $ 2,415 $ 282 $ 1,252 $ 3 $ (4,895) $ 11,443
____________
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes net purchases of capacity in the PJM market and the Sunset segment includes net sales of capacity in the PJM market.
(b)Includes $164 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 20 for unrealized net gains (losses) by segment.
Year Ended December 31, 2019
Retail Texas East West Sunset Asset Closure Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 4,983 $ - $ - $ - $ - $ - $ - $ 4,983
Retail energy charge in Northeast/Midwest 1,818 - - - - - - 1,818
Wholesale generation revenue from ISO/RTO - 1,477 629 193 751 194 - 3,244
Capacity revenue from ISO/RTO - - 170 - 197 11 - 378
Revenue from other wholesale contracts - 264 702 9 147 2 - 1,124
Total revenue from contracts with customers 6,801 1,741 1,501 202 1,095 207 - 11,547
Other revenues:
Intangible amortization (15) - (4) 4 (17) - - (32)
Hedging and other revenues (a) 86 (250) 37 132 247 42 - 294
Affiliate sales - 2,345 1,256 - 277 92 (3,970) -
Total other revenues 71 2,095 1,289 136 507 134 (3,970) 262
Total revenues $ 6,872 $ 3,836 $ 2,790 $ 338 $ 1,602 $ 341 $ (3,970) $ 11,809
____________
(a)Includes $682 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 20 for unrealized net gains (losses) by segment.
Year Ended December 31, 2018
Retail Texas East West Sunset Asset Closure Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 4,426 $ - $ - $ - $ - $ - $ - $ 4,426
Retail energy charge in Northeast/Midwest 1,123 - - - - - - 1,123
Wholesale generation revenue from ISO/RTO - 1,049 867 167 825 218 - 3,126
Capacity revenue from ISO/RTO - - 376 30 258 34 - 698
Revenue from other wholesale contracts - 214 67 6 137 - - 424
Total revenue from contracts with customers 5,549 1,263 1,310 203 1,220 252 - 9,797
Other revenues:
Intangible amortization (26) (1) (9) - (7) - - (43)
Hedging and other revenues (a) 74 (387) 16 5 (214) (106) 2 (610)
Affiliate sales - 1,622 578 - 184 225 (2,609) -
Total other revenues 48 1,234 585 5 (37) 119 (2,607) (653)
Total revenues $ 5,597 $ 2,497 $ 1,895 $ 208 $ 1,183 $ 371 $ (2,607) $ 9,144
____________
(a)Includes $380 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 20 for unrealized net gains (losses) by segment.
Retail Energy Charges
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 60 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Wholesale Generation Revenue from ISOs/RTOs
Revenue is recognized when volumes are delivered to the ISO/RTO. Revenue is recognized over time using the output method based on kilowatt hours delivered and cash is settled within 10 days of invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues.
Capacity Revenue From ISO/RTO
We offer generation capacity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers. Capacity ensures installed generation and demand response is available to satisfy system integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period. The penalties are recorded as a reduction to revenue. When capacity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue.
Revenue from Other Wholesale Contracts
Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Revenue is recognized when the service is performed. Revenue is recognized over time using the output method based on kilowatt hours delivered or other applicable measurements, and cash settles shortly after invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted for as a single performance obligation.
Other Revenues
Some of our contracts for the sale of electricity meet the definition of a derivative under the accounting standards related to derivative instruments. Revenue from derivative contracts is not considered revenue from contracts with customers under the accounting standards related to revenue. Our revenue from the sale of electricity under derivative contracts, including the impact of unrealized gains or losses on those contracts, is reported in the table above as hedging and other revenues. We have classified all sales to affiliates that are eliminated in consolidation as other revenues in the table above.
Contract and Other Customer Acquisition Costs
We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of December 31, 2020, 2019 and 2018 and January 1, 2018 was $80 million, $53 million, $38 million and $22 million, respectively. The amortization related to these costs during the year ended December 31, 2020 and 2019 totaled $46 million and $21 million, respectively, recorded as SG&A expenses, and $7 million and $9 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.
Practical Expedients
The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue.
Performance Obligations
As of December 31, 2020, we have future performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers. Therefore, an obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date. These obligations total $834 million, $496 million, $121 million, $38 million and $12 million that will be recognized in the years ending December 31, 2021, 2022, 2023, 2024 and 2025, respectively, and $7 million thereafter. Capacity revenues are recognized as capacity is made available to the related ISOs/RTOs or counterparties.
Accounts Receivable
The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:
December 31,
2020 2019
Trade accounts receivable from contracts with customers - net $ 1,169 $ 1,246
Other trade accounts receivable - net 110 119
Total trade accounts receivable - net $ 1,279 $ 1,365
6.GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
The following table provides information regarding our goodwill balance. There have been no impairments of goodwill since Emergence.
Balance at December 31, 2018 $ 2,068
Measurement period adjustments recorded in connection with the Merger 14
Goodwill recorded in connection with the Crius Transaction 257
Goodwill recorded in connection with the Ambit Transaction 214
Balance at December 31, 2019 2,553
Measurement period adjustments recorded in connection with the Crius Transaction (14)
Measurement period adjustments recorded in connection with the Ambit Transaction 44
Balance at December 31, 2020 $ 2,583
At December 31, 2020, the goodwill balance of $2.583 billion consisted of the following:
•$1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.
•$175 million arose in connection with the Merger, of which $122 million was allocated to our Texas Generation reporting unit and $53 million was allocated to our Retail reporting unit. None of the goodwill related to the Merger is deductible for tax purposes.
•$243 million of goodwill arose in connection with the Crius Transaction and was allocated entirely to our Retail reporting unit. None of the goodwill related to the Crius Transaction is deductible for tax purposes.
•$258 million of goodwill arose in connection with the Ambit Transaction and was allocated entirely to our Retail reporting unit. The goodwill related to the Ambit Transaction is deductible for tax purposes over 15 years on a straight-line basis.
Goodwill and intangible assets with indefinite useful lives are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist. We have selected October 1 as our annual goodwill test date. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2020. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition and changes in reporting unit book value.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
December 31, 2020 December 31, 2019
Identifiable Intangible Asset Gross
Carrying
Amount Accumulated
Amortization Net Gross
Carrying
Amount Accumulated
Amortization Net
Retail customer relationship $ 2,082 $ 1,434 $ 648 $ 2,078 $ 1,151 $ 927
Software and other technology-related assets 414 186 228 341 125 216
Retail and wholesale contracts 272 204 68 315 182 133
Contractual service agreements (a) 51 1 50 59 5 54
Other identifiable intangible assets (b) 96 19 77 40 15 25
Total identifiable intangible assets subject to amortization $ 2,915 $ 1,844 1,071 $ 2,833 $ 1,478 1,355
Retail trade names (not subject to amortization) 1,374 1,391
Mineral interests (not currently subject to amortization) 1 2
Total identifiable intangible assets $ 2,446 $ 2,748
____________
(a)At December 31, 2020, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization.
(b)Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).
Identifiable intangible liabilities are comprised of the following:
Year Ended December 31,
Identifiable Intangible Liability 2020 2019
Contractual service agreements
$ 129 $ 110
Purchase and sale of power and capacity
87 100
Fuel and transportation purchase contracts 73 76
Total identifiable intangible liabilities $ 289 $ 286
Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of:
Identifiable Intangible Assets and Liabilities Consolidated Statements of Operations Remaining useful lives of identifiable intangible assets at December 31,
2020 (weighted average in years) Year Ended December 31,
2020 2019 2018
Retail customer relationship Depreciation and amortization 3 $ 283 $ 275 $ 304
Software and other technology-related assets Depreciation and amortization 4 73 61 62
Retail and wholesale contracts/purchase and sale/fuel and transportation contracts Operating revenues/fuel, purchased power costs and delivery fees 3 17 23 43
Other identifiable intangible assets Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization 5 223 148 58
Total intangible asset expense (a) $ 596 $ 507 $ 467
____________
(a)Amounts recorded in depreciation and amortization totaled $360 million, $340 million and $370 million for the years ended December 31, 2020, 2019 and 2018 respectively. Amounts exclude contractual services agreements. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.
The following is a description of the separately identifiable intangible assets. In connection with fresh start reporting, the Merger, the Crius Transaction and the Ambit Transaction, the intangible assets were adjusted based on their estimated fair value as of the Effective Date, the Merger Date, the Crius Acquisition Date and the Ambit Acquisition Date, respectively, based on observable prices or estimates of fair value using valuation models.
•Retail customer relationship - Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.
•Retail trade names - Our retail trade name intangible asset represents the fair value of our retail brands, including the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets. Significant assumptions included within the development of the fair value estimate include estimated gross margins for future periods and implied royalty rates. On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2020.
•Retail and wholesale contracts/purchase and sale contracts - These intangible assets represent the value of various retail and wholesale contracts and purchase and sale contracts. The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date, the Merger Date, the Crius Acquisition Date or the Ambit Acquisition Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts.
•Contractual service agreements - Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements, rail transportation agreements and rail car leases, and are being amortized based on the expected usage of the service agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment. Amortization of rail transportation and rail car lease agreements is recorded to fuel, purchased power costs and delivery fees.
Estimated Amortization of Identifiable Intangible Assets and Liabilities
As of December 31, 2020, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.
Year Estimated Amortization Expense
2021 $ 276
2022 $ 183
2023 $ 128
2024 $ 78
2025 $ 54
7.INCOME TAXES
Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
Income Tax Expense (Benefit)
The components of our income tax expense (benefit) are as follows:
Year Ended December 31,
2020 2019 2018
Current:
U.S. Federal $ (5) $ (1) $ (13)
State 41 10 30
Total current 36 9 17
Deferred:
U.S. Federal 171 260 (8)
State 59 21 (54)
Total deferred 230 281 (62)
Total $ 266 $ 290 $ (45)
Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:
Year Ended December 31,
2020 2019 2018
Income (loss) before income taxes $ 890 $ 1,216 $ (101)
U.S. federal statutory rate 21 % 21 % 21 %
Income taxes at the U.S. federal statutory rate 187 255 (20)
Nondeductible TRA accretion (7) 5 8
State tax, net of federal benefit 32 48 22
Federal and State return to provision adjustment 13 (17) (12)
Remeasurement of historical Vistra deferred taxes for expanded state footprint - - (54)
Effect of refundable minimum tax credits no longer subject to sequestration - - (15)
Nondeductible compensation - 3 8
Nondeductible transaction costs - 2 3
Equity awards - (4) (3)
Valuation allowance on state NOLs 41 13 20
Lignite depletion (3) (6) -
Texas gross margin amended return - (3) -
Other 3 (6) (2)
Income tax expense (benefit) $ 266 $ 290 $ (45)
Effective tax rate 29.9 % 23.8 % 44.6 %
Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2020 and 2019 are as follows:
December 31,
2020 2019
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards $ 75 $ 73
Loss carryforwards 953 921
Identifiable intangible assets 293 214
Long-term debt 19 257
Employee benefit obligations 129 112
Commodity contracts and interest rate swaps 96 108
Other 47 43
Total deferred tax assets $ 1,612 $ 1,728
Noncurrent Deferred Income Tax Liabilities
Property, plant and equipment 632 554
Total deferred tax liabilities 632 554
Valuation allowance 143 110
Net Deferred Income Tax Asset $ 837 $ 1,064
At December 31, 2020, we had total deferred tax assets of approximately $837 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as federal and state net operating loss (NOL) carryforwards. Our deferred tax assets were significantly impacted by the Merger. For the year ended December 31, 2020, we recognized a partial valuation allowance of $32 million on the net operating loss carryforwards related largely to Illinois and New York due to forecasted expiration. As of December 31, 2019, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required.
At December 31, 2020, we had $3.4 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2032. At December 31, 2020, we had no remaining AMT credits refundable through the TCJA available.
The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax asset of $5 million and $3 million at December 31, 2020 and 2019, respectively.
Coronavirus Aid, Relief, and Economic Security Act (CARES Act) and Final Section 163(j) Regulations
In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. The CARES Act provides numerous relief provisions for corporate taxpayers, including modification of the utilization limitations on net operating losses, favorable expansion of the deduction for business interest expense under IRC Section 163(j) (Section 163(j)), the ability to accelerate timing of refundable AMT credits and the temporary suspension of certain payment requirements for the employer portion of social security taxes. Additionally, the final Section 163(j) regulations were issued in July 2020 and provided a critical correction to the proposed regulations with respect to the computation of adjusted taxable income. Vistra received $64 million in 2020 relating to the acceleration of AMT refunds and an approximate $350 million increase in interest expense deduction over the 2019 and 2020 tax years under the cumulative impact of these final laws and regulation pertaining to Section 163(j). Additionally, Vistra expects to receive an approximate $305 million increase in interest expense deduction in the 2021 tax year under the final Section 163(j) regulations. We do not anticipate a material impact to the effective tax rate from these impacts. Vistra is also utilizing the CARES Act payroll deferral mechanism to defer the payment of approximately $22 million from 2020 to 2021 and 2022.
Liability for Uncertain Tax Positions
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial for the years ended December 31, 2020, 2019 and 2018. The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets for the years ended December 31, 2020, 2019 and 2018.
Year Ended December 31,
2020 2019 2018
Balance at beginning of period, excluding interest and penalties $ 126 $ 39 $ -
Additions allocated in the Merger - - 39
Additions based on tax positions related to prior years 3 3 -
Reductions based on tax positions related to prior years (90) - -
Additions based on tax positions related to the current year - 87 -
Settlements with taxing authorities - (3) -
Balance at end of period, excluding interest and penalties $ 39 $ 126 $ 39
Vistra and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities. The IRS has notified us of its intention to open an audit regarding the 2018 tax year. Crius is currently under audit by the IRS for the tax years 2015 and 2016. Uncertain tax positions totaling $39 million at December 31, 2020 reflect the final regulations under Section 163(j) that were released in July 2020, and we have adjusted deferred tax assets and liabilities by $87 million in the year ended December 31, 2020. Uncertain tax positions totaling $39 million at December 31, 2018 arose in connection with the Merger as discussed in Note 2.
Tax Matters Agreement
On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.
Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.
Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off.
Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.
8.TAX RECEIVABLE AGREEMENT OBLIGATION
On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first-lien creditors of TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Such TRA Rights are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 19).
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2020, 2019 and 2018.
Year Ended December 31,
2020 2019 2018
TRA obligation at the beginning of the period $ 455 $ 420 $ 357
Accretion expense 64 59 65
Changes in tax assumptions impacting timing of payments (a) (69) (22) 14
Impacts of Tax Receivable Agreement (5) 37 79
Payments - (2) (16)
TRA obligation at the end of the period 450 455 420
Less amounts due currently (3) - -
Noncurrent TRA obligation at the end of the period $ 447 $ 455 $ 420
____________
(a)During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA obligation totaling $69 million as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) regulations and the anticipated tax benefits from renewable development projects. During the year ended December 31, 2019, we recorded a decrease to the carrying value of the TRA obligation totaling approximately $22 million as a result of adjustments to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra's state income tax profile, including the Dynegy, Crius and Ambit acquisitions. During the year ended December 31, 2018, we recorded an increase to the carrying value of the TRA obligation totaling $14 million related to changes in the timing of estimated payments resulting changes in the timing of estimated payments and new multistate tax impacts resulting from the Merger.
As of December 31, 2020, the estimated carrying value of the TRA obligation totaled $450 million, which represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21%, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra now operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of December 31, 2020, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be paid during the next 15 years, and the final payment expected to be made around the year 2056 (if the TRA is not terminated earlier pursuant to its terms).
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation.
9.EARNINGS PER SHARE
Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
Year Ended December 31,
2020 2019 2018
Net income (loss) attributable to common stock - basic $ 636 $ 928 $ (54)
Weighted average shares of common stock outstanding - basic 488,668,263 494,146,268 504,954,371
Net income (loss) per weighted average share of common stock outstanding - basic $ 1.30 $ 1.88 $ (0.11)
Dilutive securities: Stock-based incentive compensation plan 2,422,205 5,789,223 -
Weighted average shares of common stock outstanding - diluted 491,090,468 499,935,490 504,954,371
Net income (loss) per weighted average share of common stock outstanding - diluted $ 1.30 $ 1.86 $ (0.11)
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 12,553,414, 2,447,850 and 14,165,813 shares for the years ended December 31, 2020, 2019 and 2018, respectively.
10.ACCOUNTS RECEIVABLE FINANCING
Accounts Receivable Securitization Program
TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). The Receivables Facility was renewed in July 2020, extending the term of the Receivables Facility to July 2021, with the ability to borrow $550 million beginning with the settlement date in July 2020 until the settlement date in August 2020, $625 million from the settlement date in August 2020 until the settlement date in November 2020, $550 million from the settlement date in November 2020 until the settlement date in December 2020 and $450 million thereafter for the remaining term of the Receivables Facility. In December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and TriEagle Energy, as originators, and increase the commitment of the Purchasers to $500 million for the remaining term of the Receivables Facility. In February 2021, the Receivables Facility was amended to allow for a one-time, $596 million borrowing to take advantage of a higher receivable balance at such time. The borrowing limit is expected to return to $500 million in March 2021.
In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limits described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.
As of December 31, 2020, outstanding borrowings under the receivables facility totaled $300 million and were supported by $735 million of RecCo gross receivables. As of December 31, 2019, outstanding borrowings under the Receivables Facility totaled $450 million and were supported by $629 million of RecCo gross receivables. As of February 23, 2021, outstanding borrowings under the receivables facility totaled approximately $596 million and were supported by approximately $774 million of RecCo gross receivables..
Repurchase Facility
In October 2020, TXU Energy and the other originators under the Receivables Facility entered into a $125 million repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Transactions). Each Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.
TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the schedule termination of the Receivables Facility.
As of December 31, 2020, there were no borrowings under the Repurchase Facility. In February 2021, the Company borrowed $125 million under the Repurchase Facility.
11.LONG-TERM DEBT
Amounts in the table below represent the categories of long-term debt obligations incurred by the Company.
December 31,
2020 2019
Vistra Operations Credit Facilities $ 2,572 $ 2,700
Vistra Operations Senior Secured Notes:
3.550% Senior Secured Notes, due July 15, 2024
1,500 1,500
3.700% Senior Secured Notes, due January 30, 2027
800 800
4.300% Senior Secured Notes, due July 15, 2029
800 800
Total Vistra Operations Senior Secured Notes 3,100 3,100
Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026
1,000 1,000
5.625% Senior Unsecured Notes, due February 15, 2027
1,300 1,300
5.000% Senior Unsecured Notes, due July 31, 2027
1,300 1,300
Total Vistra Operations Senior Unsecured Notes 3,600 3,600
Vistra Senior Unsecured Notes:
5.875% Senior Unsecured Notes, due June 1, 2023
- 500
8.000% Senior Unsecured Notes, due January 15, 2025
- 81
8.125% Senior Unsecured Notes, due January 30, 2026
- 166
Total Vistra Senior Unsecured Notes - 747
Other:
Forward Capacity Agreements 45 161
Equipment Financing Agreements 68 99
8.82% Building Financing due semiannually through February 11, 2022 (a)
10 15
Other 3 12
Total other long-term debt 126 287
Unamortized debt premiums, discounts and issuance costs (b) (68) (55)
Total long-term debt including amounts due currently 9,330 10,379
Less amounts due currently (95) (277)
Total long-term debt less amounts due currently $ 9,235 $ 10,102
____________
(a)Obligation related to a corporate office space finance lease. This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our consolidated balance sheets.
(b)Includes impact of recording debt assumed in the Merger at fair value.
Vistra Operations Credit Facilities
At December 31, 2020, the Vistra Operations Credit Facilities consisted of up to $5.297 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $2.725 billion, including a $2.35 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.572 billion (Term Loan B-3 Facility). These amounts reflect the following transactions and amendments completed in 2020, 2019 and 2018:
•In March 2020, Vistra Operations repurchased $100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $93.875 and cancelled them. We recorded an extinguishment gain of $6 million on the transaction in the year ended December 31, 2020.
•In November 2019, Vistra Operations used the net proceeds from the November 2019 Senior Secured Notes Offering described below and $799 million of incremental borrowings under the Term Loan B-3 Facility to repay the entire amount outstanding of $1.897 billion of term loans under the B-1 Facility (Term Loan B-1 Facility). Fees and expenses related to the transactions totaled $2 million in the year ended December 31, 2019, which were recorded as interest expense and other charges on the consolidated statements of operations.
•In October 2019, Vistra Operations borrowed $550 million under the Revolving Credit Facility. The proceeds of the borrowings were used for general corporate purposes, including the funding of a $425 million dividend to Vistra to pay the principal, premium and interest due in connection with the redemption by Vistra of the entire $387 million aggregate principal amount outstanding of 7.625% senior notes described below. In November 2019, Vistra Operations repaid $200 million under the Revolving Credit Facility.
•In June 2019, Vistra Operations used the net proceeds from the June 2019 Senior Secured Notes Offerings (described below) to repay $889 million under the Term Loan B-1 Facility, the entire amount outstanding of $977 million of term loans under the B-2 Facility (Term Loan B-2 Facility, and together with the Term Loan B-1 Facility and the Term Loan B-3 Facility, the Term Loan B Facility) and $134 million under the Term Loan B-3 Facility. We recorded an extinguishment loss of $4 million on the transactions in the year ended December 31, 2019.
•In March 2019 and May 2019, the Vistra Operations Credit Facilities were amended whereby we obtained $225 million of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $50 million. Fees and expenses related to the amendments to the Vistra Operations Credit Facilities totaled $2 million for the year ended December 31, 2019, which were capitalized as a noncurrent asset.
•In June 2018, the Vistra Operations Credit Facilities were amended whereby we incurred $2.050 billion of borrowings under the new Term Loan B-3 Facility and obtained $1.640 billion of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $1.585 billion. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. As discussed below, the proceeds from the Term Loan B-3 Facility were used to repay borrowings under the credit agreement that Vistra assumed from Dynegy in connection with the Merger. Additionally, letter of credit term loans totaling $500 million (Term Loan C Facility) were repaid using $500 million of cash from collateral accounts used to backstop letters of credit. Fees and expenses related to the amendment to the Vistra Operations Credit Facilities totaled $42 million in the year ended December 31, 2018, of which $23 million was recorded as interest expense and other charges on the consolidated statements of operations, $9 million was capitalized as a reduction in the carrying amount of the debt and $10 million was capitalized as a noncurrent asset.
During the year ended December 31, 2020, we borrowed $1.075 billion and repaid $1.425 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes.
The Vistra Operations Credit Facilities and related available capacity at December 31, 2020 are presented below.
December 31, 2020
Vistra Operations Credit Facilities Maturity Date Facility
Limit Cash
Borrowings Letters of Credit Outstanding Available
Capacity
Revolving Credit Facility (a) June 14, 2023 $ 2,725 $ - $ 737 $ 1,988
Term Loan B-3 Facility (b) December 31, 2025 2,572 2,572 -
Total Vistra Operations Credit Facilities $ 5,297 $ 2,572 $ 737 $ 1,988
___________
(a)Revolving Credit Facility to be used for general corporate purposes. The Facility includes a $2.35 billion letter of credit sub-facility. Letters of credit outstanding reduce our available capacity. Cash borrowings under the Revolving Credit Facility are reported in short-term borrowings in our consolidated balance sheets.
(b)Beginning in 2020, cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual amount equal to 1.00% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed.
In February 2018, June 2018 and November 2019, certain pricing terms for the Vistra Operations Credit Facilities were amended. We accounted for these transactions as modifications of debt. At December 31, 2020, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-3 Facility bears interest based on applicable LIBOR rates plus fixed spreads of 1.75%. At December 31, 2020, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 1.90% under the Term Loan B-3 Facility. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the available Revolving Credit Facility.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.
The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 4.25 to 1.00. Although the period ended December 31, 2020 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such time. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.
Interest Rate Swaps - Vistra employs interest rate swaps to hedge our exposure to variable rate debt. As of December 31, 2020, Vistra has entered into the following series of interest rate swap transactions.
Notional Amount Expiration Date Rate Range
Swapped to fixed $3,000 July 2023 3.67 % - 3.91%
Swapped to variable $700 July 2023 3.20 % - 3.23%
Swapped to fixed (a) $720 February 2024 3.71 % - 3.72%
Swapped to variable $720 February 2024 3.20 % - 3.20%
Swapped to fixed (b) $3,000 July 2026 4.72 % - 4.79%
Swapped to variable (b) $700 July 2026 3.28 % - 3.33%
____________
(a)In June 2018, we completed the novation of $1.959 billion of Vistra (legacy Dynegy) interest rate swaps to Vistra Operations, of which $398 million expired and $841 million were terminated in June 2019.
(b)Effective from July 2023 through July 2026.
During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.
Secured Letter of Credit Facilities
In August and September 2020, Vistra entered into four uncommitted 364-day standby letter of credit facilities (Secured LOC Facilities) that are each secured by a first lien on all of Vista Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities). At December 31, 2020, $303 million of letters of credit were outstanding under the Secured LOC Facilities.
Alternate Letter of Credit Facilities
Two alternate letter of credit facilities (each, an Alternate LOC Facility) became effective in the year ended December 31, 2019. One Alternate LOC Facility with an aggregate facility limit of $250 million matured in December 2020. The remaining Alternate LOC Facility with an aggregate facility limit of $250 million matures in December 2021. At December 31, 2020, $245 million of letters of credit were outstanding under this Alternate LOC Facility.
Vistra Operations Senior Secured Notes
In 2019, Vistra Operations issued and sold $3.1 billion aggregate principal amount of senior secured notes (June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes) in offerings (the June 2019 Senior Secured Notes Offering and the November 2019 Senior Secured Notes Offering) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the following:
Senior Secured Notes Maturity Year Interest Terms
(Due Semiannually in Arrears) June 2019
Senior Secured Notes Offering (a) November 2019 Senior Secured Notes Offering (b)
3.550% Senior Secured Notes
2024 January 15 and July 15 $ 1,200 $ 300
3.700% Senior Secured Notes
2027 January 30 and July 30 - 800
4.300% Senior Secured Notes
2029 January 15 and July 15 800 -
Total senior secured notes $ 2,000 $ 1,100
Net proceeds $ 1,976 $ 1,099
Debt issuance and other fees (c) $ 20 $ 10
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(a)The June 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to prepay certain amounts outstanding and accrued interest (together with fees and expenses) under the Term Loan B Facility.
(b)The November 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and J.P. Morgan Securities LLC., as representative of the several initial purchasers. Net proceeds, together with borrowings under the Term Loan B-3 Facility and cash on hand, were used to repay the entire amount outstanding and accrued interest (together with fees and expenses) under the Term Loan B-1 Facility.
(c)Capitalized as a reduction in the carrying amount of the debt.
The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes (collectively, the Senior Secured Notes) provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities, which consists of a substantial portion of the property, assets and rights owned by Vistra Operations and certain direct and indirect subsidiaries of Vistra Operations as subsidiary guarantors (collectively, the Guarantor Subsidiaries) as well as the stock of Vistra Operations held by Vistra Intermediate. The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior, unsecured long-term debt securities obtain an investment grade rating from two out of the three rating agencies, subject to reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt securities or downgrade such rating below investment grade. The Vistra Operations Senior Secured Indenture contains certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.
Vistra Operations Senior Unsecured Notes
In 2018 and 2019, Vistra Operations issued and sold $3.6 billion aggregate principal amount of senior unsecured notes in offerings (the August 2018 Senior Unsecured Notes Offering, the February 2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offerings) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the following:
Senior Unsecured Notes Maturity Year Interest Terms
(Due Semiannually in Arrears) August 2018 Senior Unsecured Notes Offering (a) February 2019 Senior Unsecured Notes Offering (b) June 2019
Senior Unsecured Notes Offering (c)
5.500% Senior Unsecured Notes
2026 March 1 and September 1 $ 1,000 $ - $ -
5.625% Senior Unsecured Notes
2027 February 15 and August 15 - 1,300 -
5.000% Senior Unsecured Notes
2027 January 31 and July 31 - - 1,300
Total $ 1,000 $ 1,300 $ 1,300
Net Proceeds $ 990 $ 1,287 $ 1,287
Debt issuance and other fees (d) $ 12 $ 16 $ 13
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(a)The 5.500% senior unsecured notes due 2026 (the August 2018 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Citigroup Global Markets Inc., as representative of the several initial purchasers. Net proceeds, together with cash on hand and cash received from the funding of the Receivables Facility (see Note 10), were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the 2018 Tender Offers (defined below).
(b)The 5.625% senior unsecured notes due 2027 (the February 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P. Morgan Securities LLC., as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with (i) the February 2019 Tender Offer, (defined below) and (ii) the redemption of approximately $35 million aggregate principal amount of our 7.375% senior unsecured notes due 2022 (7.375% senior notes) and approximately $25 million aggregate principal amount of our outstanding 8.034% senior unsecured notes due 2024 (8.034% senior notes).
(c)The 5.000% senior unsecured notes due 2027 (the June 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Goldman Sachs & Co. LLC, as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with (i) the June 2019 Tender Offer (defined below) and (ii) the redemption of approximately $306 million of our outstanding 7.375% senior notes and approximately $87 million of our 7.625% senior unsecured notes due 2024 (7.625% senior notes) in July 2019. We recorded an extinguishment gain of $2 million on the redemptions in the year ended December 31, 2019.
(d)Capitalized as a reduction in the carrying amount of the debt.
The indentures governing the June 2019 Senior Unsecured Notes, the February 2019 Senior Unsecured Notes and the August 2018 Senior Unsecured Notes (collectively, as each may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.
Debt Repurchase Program
In November 2018, our board of directors (the Board) authorized a bond repurchase program under which up to $200 million principal amount of outstanding Vistra Senior Unsecured Notes could be repurchased. Through June 30, 2019, $119 million principal amount of Vistra Senior Unsecured Notes had been repurchased. In July 2019, the Board authorized up to $1.0 billion to repay or repurchase any outstanding debt of the Company (or its subsidiaries), with that authority superseding the remaining availability under the $200 million bond repurchase program. Through April 2020, $684 million amount of debt had been repurchased under the $1.0 billion July 2019 authorization, including the repurchase of $100 million principal amount of Term Loan B-3 Facility borrowings discussed above and the redemption of $81 million aggregate principal amount outstanding of 8.000% senior unsecured notes due 2025 (8.000% senior notes) discussed below. In April 2020, the Board authorized up to $1.0 billion to repay or repurchase additional outstanding debt, with this new authority superseding and replacing the $316 million of availability under the previously authorized $1.0 billion debt repurchase program. Through December 31, 2020, approximately $666 million had been repurchased under the $1.0 billion April 2020 authorization, consisting of the redemption of the Vistra 5.875% senior unsecured notes due 2023 (5.875% senior notes) and the redemption of the Vistra 8.125% senior unsecured notes due 2026 (8.125% senior notes), each as described below.
Vistra Senior Unsecured Notes
On the Merger Date, Vistra assumed $6.138 billion principal amount of Dynegy's senior unsecured notes (Vistra Senior Unsecured Notes. In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.
Following the redemption, repurchase and tender offer transactions below, Vistra had no outstanding senior notes at the Parent level.
Vistra Senior Unsecured Notes Maturity Year 2018 Redemptions/Repurchases (a) August
2018 Tender Offer (b) February 2019 Tender Offer (c) June
2019 Tender Offer (d) 2019 Redemptions (e) 2020 Redemptions (f)
6.750%Senior Unsecured Notes
2019 $ 850 $ - $ - $ - $ - $ -
7.375% Senior Unsecured Notes
2022 43 - 1,193 173 341 -
5.875% Senior Unsecured Notes
2023 - - - - - 500
7.625% Senior Unsecured Notes
2024 77 26 - 672 475 -
8.034% Senior Unsecured Notes
2024 - 163 - - 25 -
8.000% Senior Unsecured Notes
2025 - 669 - - - 81
8.125%Senior Unsecured Notes
2026 - 684 - - - 166
Total $ 970 $ 1,542 $ 1,193 $ 845 $ 841 $ 747
Extinguishment gain/(loss) $ - $ (27) $ 7 $ 7 $ 11 $ 11
____________
(a)In May 2018, $850 million of outstanding 6.75% senior unsecured notes due 2019 were redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest up to but not including the date of redemption. Fees and expenses related to the redemption totaled $14 million in the year ended December 31, 2018 and were recorded as interest expense and other charges on the consolidated statements of operations. In addition, Vistra repurchased $119 million of Vistra Senior Unsecured Notes under the bond repurchase program described above.
(b)In August 2018, Vistra used the net proceeds from the August 2018 Senior Unsecured Notes Offering, proceeds from the Receivables Facility (see Note 10) and cash on hand to fund cash tender offers (the 2018 Tender Offers) to purchase for cash $1.542 billion aggregate principal amount of Vistra Senior Unsecured Notes.
(c)In February 2019, Vistra used the net proceeds from the February 2019 Senior Unsecured Notes Offering to fund a cash tender offer (the February 2019 Tender Offer) to purchase for cash $1.193 billion aggregate principal amount of 7.375% senior notes.
(d)In June 2019, Vistra used the net proceeds from the June 2019 Notes Offering to fund a cash tender offer (the June 2019 Tender Offer) to purchase for cash $173 million of 7.375% senior notes and $672 million of 7.625% senior notes. In July 2019, Vistra accepted and settled an additional approximately $1 million aggregate principal amount of outstanding 7.625% senior notes that were tendered after the early tender date of the June 2019 Tender Offer.
(e)In November 2019, Vistra redeemed $387 million aggregate principal amount outstanding of 7.625% senior notes at a redemption price equal to 103.8% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption (the 2019 Redemption). Vistra redeemed $341 million, $87 million and $25 million aggregate principal amount of 7.375% senior notes, 7.625% senior notes and 8.034% senior notes, respectively, using proceeds from the February 2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offerings discussed above.
(f)In January 2020, June 2020 and July 2020, Vistra redeemed aggregate principal amounts of $81 million of 8.000% senior notes, $500 million of 5.875% senior notes and $166 million of 8.125% senior notes, respectively, at redemption prices of 104%, 100.979% and 104.063%, respectively, of the aggregate principal amounts thereof, plus accrued and unpaid interest to, but excluding, the dates of redemption (the 2020 Redemptions, and together with the 2019 Redemption, the Redemptions).
February 2019 Consent Solicitation - In connection with the February 2019 Tender Offer, Vistra also commenced solicitation of consents from holders of the 7.375% senior notes. Vistra received the requisite consents from the holders of the 7.375% senior notes and amended the indenture governing these senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default.
August 2018 Consent Solicitations - In connection with the 2018 Tender Offers, Vistra also commenced solicitations of consents from holders of the 7.375% senior notes, the 7.625% senior notes, the 8.034% senior notes, the 8.000% senior notes and the 8.125% senior notes to amend certain provisions of the applicable indentures governing each series of senior notes and the registration rights agreement with respect to the 8.125% senior notes. Vistra received the requisite consents from the holders of the 8.034% senior notes, the 8.000% senior notes and the 8.125% senior notes (collectively, the Consent Senior Notes) and amended (a) the indentures governing each series of the applicable senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default and (b) the registration rights agreement with respect to the 8.125% senior notes to remove, among other things, the requirement that Vistra commence an exchange offer to issue registered securities in exchange for the existing, nonregistered notes.
Other Long-Term Debt
Amortizing Notes - On the Merger Date, Vistra assumed the obligations of Dynegy's senior unsecured amortizing note (Amortizing Notes) that matured on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 14). Each installment payment per Amortizing Note was paid in cash and constituted a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%. Interest was calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments were applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the indenture (Amortizing Notes Indenture). On the maturity date, the Company paid all amounts due under the Amortizing Notes Indenture and the Amortizing Notes Indenture ceased to be of further force and effect.
Forward Capacity Agreements - On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Forward Capacity Agreements). The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2020-2021 in the amount of $45 million. We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as long-term debt with an implied interest rate of 1.14%.
Equipment Financing Agreements - On the Merger Date, the Company assumed Dynegy's Equipment Financing Agreements. Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units. We financed these parts and equipment under agreements with maturities ranging from 2021 to 2026.
Mandatorily Redeemable Subsidiary Preferred Stock - In October 2019, PrefCo voluntarily redeemed the entire $70 million aggregate principal amount outstanding of its authorized preferred stock at a price per share equal to the preferred liquidation amount, plus accrued and unpaid dividends to and including the date of redemption.
Debt Assumed in Crius Transaction - On the Crius Acquisition Date, Vistra assumed $140 million in long-term debt obligations in connection with the Crius Transaction consisting of the following:
•$44 million of 9.5% promissory notes due July 2025 (2025 promissory notes);
•$8 million of 2% Connecticut Department of Economic and Community Development (CT DECD) term loans due February 2027; and
•$88 million of borrowings and $9 million of issued letters of credit under the legacy Crius credit facility.
In July 2019, borrowings of $88 million under the legacy Crius credit facility were repaid using cash on hand. In November 2019, (i) borrowings of approximately $38 million under the 2025 promissory notes were repaid using cash on hand and (ii) borrowings of approximately $2 million were offset by legacy indemnification obligations of the holders of the 2025 promissory notes. In November 2019, borrowings of $8 million under the Connecticut Department of Economic and Community Development term loans were repaid using cash on hand.
Vistra (legacy Dynegy) Credit Agreement - On the Merger Date, Vistra assumed the obligations under Dynegy's $3.563 billion credit agreement consisting of a $2.018 billion senior secured term loan facility due 2024 and a $1.545 billion senior secured revolving credit facility. As of the Merger Date, there were no cash borrowings and $656 million of letters of credit outstanding under the senior secured revolving credit facility. On April 23, 2018, $70 million of the senior secured revolving credit facility matured. In June 2018, the $2.018 billion senior secured term loan facility due 2024 was repaid using proceeds from the Term Loan B-3 Facility. In addition, all letters of credit outstanding under the senior secured revolving credit facility were replaced with letters of credit under the amended Vistra Operations Credit Facilities discussed above, and the revolving credit facility assumed from Dynegy in connection with the Merger was paid off in full and terminated.
Maturities
Long-term debt maturities at December 31, 2020 are as follows:
December 31, 2020
2021 $ 98
2022 44
2023 40
2024 1,540
2025 2,470
Thereafter 5,206
Unamortized premiums, discounts and debt issuance costs (68)
Total long-term debt, including amounts due currently $ 9,330
12.LEASES
Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 37 years. Our leases include options to renew up to 15 years. Certain leases also contain options to terminate the lease.
Lease Cost
The following table presents costs related to lease activities:
Year Ended December 31,
2020 2019
Operating lease cost $ 14 $ 14
Finance lease:
Finance lease right-of-use asset amortization 7 4
Interest on lease liabilities 7 4
Total finance lease cost 14 8
Variable lease cost (a) 29 26
Short-term lease cost 31 19
Sublease income (b) (8) (8)
Net lease cost $ 80 $ 59
____________
(a)Represents coal stockpile management services, common area maintenance services and rail car payments based on the number of rail cars used.
(b)Represents sublease income related to real estate leases.
Balance Sheet Information
The following table presents lease related balance sheet information:
December 31,
2020 2019
Lease assets:
Operating lease right-of-use assets $ 45 $ 44
Finance lease right-of-use assets (net of accumulated depreciation) 182 $ 59
Total lease right-of-use assets 227 103
Current lease liabilities:
Operating lease liabilities 8 14
Finance lease liabilities 8 8
Total current lease liabilities 16 22
Noncurrent lease liabilities:
Operating lease liabilities 40 41
Finance lease liabilities 206 78
Total noncurrent lease liabilities 246 119
Total lease liabilities $ 262 $ 141
Cash Flows and Other Information
The following table presents lease related cash flows and other information:
Year Ended December 31,
2020 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 17 $ 17
Operating cash flows from finance leases 5 4
Finance cash flows from finance leases 10 4
Non-cash disclosure upon commencement of new lease:
Right-of-use assets obtained in exchange for new operating lease liabilities 14 95
Right-of-use assets obtained in exchange for new finance lease liabilities 108 13
Non-cash disclosure upon modification of existing lease:
Modification of operating lease right-of-use assets (1) (41)
Modification of finance lease right-of-use assets 23 50
Weighted Average Remaining Lease Term
The following table presents weighted average remaining lease term information:
December 31,
2020 2019
Weighted average remaining lease term:
Operating lease 12.3 years 7.5 years
Finance lease 24.2 years 16.2 years
Weighted average discount rate:
Operating lease 5.80% 5.34 %
Finance lease 4.92% 5.84 %
Maturity of Lease Liabilities
The following table presents maturity of lease liabilities:
Operating Lease Finance Lease Total Lease
2021 $ 11 $ 14 $ 25
2022 8 20 28
2023 9 19 28
2024 5 19 24
2025 3 19 22
Thereafter 41 385 426
Total lease payments 77 476 553
Less: Interest (29) (262) (291)
Present value of lease liabilities $ 48 $ 214 $ 262
As of December 31, 2020, we have approximately $7 million of operating leases that have not yet commenced.
13.COMMITMENTS AND CONTINGENCIES
Contractual Commitments
At December 31, 2020, we had contractual commitments under long-term service and maintenance contracts, energy-related contracts, leases and other agreements as follows.
Long-Term Service and Maintenance Contracts Coal purchase and
transportation agreements Pipeline transportation and storage reservation fees Nuclear
Fuel Contracts Other
Contracts
2021 $ 165 $ 516 $ 100 $ 92 $ 256
2022 186 47 73 43 49
2023 137 34 49 57 29
2024 142 36 36 40 24
2025 170 37 30 36 11
Thereafter 1,824 79 111 107 80
Total $ 2,624 $ 749 $ 399 $ 375 $ 449
The table above excludes TRA and pension and OPEB plan obligations due to the uncertainty in the timing of those payments.
Expenditures under our coal purchase and coal transportation agreements totaled $845 million, $1.092 billion, and $955 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Rent reported as operating costs and SG&A expenses totaled $111 million, $89 million, and $74 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2020, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees in the near term.
Letters of Credit
At December 31, 2020, we had outstanding letters of credit totaling $1.286 billion as follows:
•$878 million to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;
•$190 million to support battery and solar development projects;
•$34 million to support executory contracts and insurance agreements;
•$102 million to support our REP financial requirements with the PUCT; and
•$82 million for other credit support requirements.
Surety Bonds
At December 31, 2020, we had outstanding surety bonds totaling $100 million to support performance under various contracts and legal obligations in the normal course of business.
Litigation and Regulatory Proceedings
Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.
Gas Index Pricing Litigation - We, through our subsidiaries, and other companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. We remain as defendants in two consolidated putative class actions (Wisconsin) and one individual action (Kansas) both pending in federal court in those states. The Kansas action is currently on appeal in the U.S. Court of Appeals for the Tenth Circuit.
Wood River Rail Dispute - In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads. Settlement discussions required under the dispute resolution process have been unsuccessful. In March 2018, BNSF Railway Company (BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration and an arbitration hearing is currently scheduled for March 2021.
Coffeen and Duck Creek Rail Disputes - In April 2020, IPH, LLC (IPH) received notification that BNSF and NS were initiating dispute resolution related to IPH's suspension of its Coffeen Rail Transportation Agreement with the railroads, and Illinois Power Resources Generating, LLC (IPRG), received notification that BNSF was initiating dispute resolution related to IPRG's suspension of its Duck Creek Rail Transportation Agreement with BNSF. In November 2019, IPH and IPRG sent suspension notices to the railroads asserting that the MPS rule requirement to retire at least 2,000 megawatts of generation (see discussion below) was a change-in-law under the agreement that rendered continued operation of the plants no longer economically feasible. In addition, IPH and IPRG asserted that the MPS rule's retirement requirement also qualified as a force majeure event under the agreements excusing performance.
ME2C Patent Dispute - In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint in federal court in Delaware against numerous parties, including Vistra and some of its subsidiaries (collectively, the Vistra defendants), and its amended complaint in July 2020. The amended complaint alleges that the Vistra defendants infringed five patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fueled plants. The amended complaint seeks injunctive relief and unspecified damages. In July 2020, the plaintiffs and the Vistra defendants entered into an agreement resolving all the claims alleged against the Vistra defendants in the complaint. The court signed its stipulation and order of dismissal in July 2020, dismissing the Vistra defendants from the lawsuit.
Climate Change
In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (the Environment Executive Order) which directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions discussed below are now subject to this review.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals to reduce nationwide CO2 emissions. Various parties filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court). In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's new rule that replaces the Clean Power Plan, the Affordable Clean Energy rule, discussed below. In September 2019, the D.C. Circuit Court granted petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.
In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule develops emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. The ACE rule set a deadline of July 2022 for states to submit their plans for regulating GHG emissions from existing facilities. States where we operate coal plants (Texas, Illinois and Ohio) have begun the development of their state plans to comply with the rule. Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power Plan in the D.C. Circuit Court, and the D.C. Circuit Court heard argument on those issues in October 2020. In January 2021, the D.C. Circuit Court vacated the ACE rule and remanded the rule to the EPA for further action. In its decision, the D.C. Circuit Court concluded that the EPA's basis for repealing the Clean Power Plan and adopting the ACE rule was not supported by the Clean Air Act. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units. Vistra submitted comments on that proposed rulemaking in March 2019. In January 2021, the EPA, just prior to the transition to the Biden administration, issued a final rule setting forth a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. The final rule excludes sectors from future regulation where GHG emissions make up less than three percent of U.S. GHG emissions. The final rule did not set any specific emission limits for new, modified, or reconstructed electric utility generating units. The ACE rule and the rule on significant contribution are subject to the Environment Executive Order discussed above.
Regional Haze - Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP). For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units (including our Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. The retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply with this BART rule for SO2. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas's SIP that determines that no electricity generation units are subject to BART for particulate matter. Various parties filed a petition challenging the rule in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA in the Fifth Circuit Court action. In March 2018, the Fifth Circuit Court abated its proceedings pending conclusion of the EPA's reconsideration process. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. In October 2020, environmental groups petitioned for review of this rule in both the D.C. Circuit Court and the Fifth Circuit Court. 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 for information regarding the retirement of these four plants.
SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would revise its previous nonattainment designations and each area at issue would be designated unclassifiable. In September 2019, we submitted comments in support of the proposed Error Correction Rule. In April 2020, the Sierra Club filed suit to compel the EPA to issue a Finding of Failure to submit an attainment plan with respect to the three areas in Texas. In August 2020, the EPA issued a Finding of Failure for Texas to submit an attainment plan. In September 2020, the EPA proposed a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, which, if finalized, would redesignate those areas as attainment based on monitoring data supporting an attainment designation. We expect the TCEQ to develop a SIP for Texas for submittal to the EPA in 2021.
Effluent Limitation Guidelines (ELGs)
In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration of the ELG rule would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rule for the application of effluent limitations for FGD and bottom ash wastewaters from November 1, 2018 to November 1, 2020. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to effluent limitations. The remainder of the case proceeded, and in April 2019 the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. In November 2019, the EPA issued a proposal that would extend the compliance deadline for FGD wastewater to no later than December 31, 2025 and maintains the December 31, 2023 compliance date for bottom ash transport water. The proposal also creates new sub-categories of facilities with more flexible FGD compliance options, including a retirement exemption to 2028 and a low utilization boiler exemption. The proposed rule also modified some of the FGD final effluent limitations. We filed comments on the proposal in January 2020. The EPA published the final rule in October 2020. The final rule extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. Notification to the state agency on the retirement exemption is due by October 2021. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. The final rule is subject to the Environment Executive Order discussed above.
Coal Combustion Residuals (CCR)/Groundwater
In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of the CCR rule that the agency issued in 2015. Among other changes, the 2018 revisions extended closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. Also, in August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In December 2019, the EPA issued a proposed rule containing a revised closure deadline for unlined CCR impoundments and new procedures for seeking extensions of that revised closure deadline. We filed comments on the proposal in January 2020. In August 2020, the EPA issued a rule finalizing the December 2019 proposal, establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned for review of this rule in the D.C. Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities. In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake. In October 2020, the EPA published an advanced notice of proposed rulemaking requesting information to inform the EPA in the development of a rule to address legacy impoundments that existed prior to the 2015 CCR regulation as required by the August 2018 D.C. Circuit Court decision. We filed comments on this proposal in February 2021. The rules on revised closure deadlines and alternative liner demonstrations are subject to the Environment Executive Order discussed above.
MISO - In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of those closure plans.
At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In May 2018, Prairie Rivers Network filed a citizen suit in federal court in Illinois against DMG, alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. Plaintiffs have appealed the judgment to the U.S. Court of Appeals for the Seventh Circuit and argument was heard in November 2020. In April 2019, PRN also filed a complaint against DMG before the IPCB, alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992. This matter is in the very early stages.
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility and that notice has since been referred to the Illinois Attorney General.
In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the Coffeen, Edwards and Joppa generation facilities are causing exceedances of the applicable groundwater standards.
In 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 contained in our AROs, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.
MISO 2015-2016 Planning Resource Auction
In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint.
In October 2015, FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA.
In December 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order.
In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. With the issuance of the order, this matter has been resolved in Dynegy's favor. The request for rehearing was denied by FERC in March 2020. The order was appealed by Public Citizen, Inc. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020. The appeal remains pending.
Other Matters
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Labor Contracts
We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal- and nuclear-fueled generation operations and some of our natural gas-fueled generation operations expire on various dates between May 2021 and November 2023, but remain effective thereafter unless and until terminated by either party. We are also presently negotiating the terms of first contracts at two of our natural gas-fueled generation facilities. While we cannot predict the outcome of labor contract negotiations, we do not expect any negotiated terms in our new collective bargaining agreements or changes in our existing agreements to have a material adverse effect on our results of operations, liquidity or financial condition.
Nuclear Insurance
Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination and accidental premature decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.
With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $13.8 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $13.8 billion limit for a single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facility resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).
Under the SFP, in the event of any single nuclear liability loss in excess of $450 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S. is subject to an annual assessment of up to $137.6 million. This approximately $137.6 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2023. Assessments are currently limited to $20.5 million per operating licensed reactor per year per incident. As of December 31, 2020, our maximum potential assessment under the industry retrospective plan would be approximately $275 million per incident but no more than $41 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $450 million per accident at any nuclear facility.
The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion (subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per accident), above which we are self-insured.
We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service for more than twelve weeks as a result of covered direct physical damage. Such coverage provides for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $3.6 million for the remaining 71 weeks. The total maximum coverage is $328 million for non-nuclear property damage and $490 million for nuclear property damage. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.
14.EQUITY
Equity Issuances and Repurchases
Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2020, 2019 and 2018 are reflected in the table below.
Shares
Issued Treasury
Shares Shares Outstanding
Balance at December 31, 2017 428,398,802 - 428,398,802
Shares issued (a) (b) 97,639,105 - 97,639,105
Shares retired (6,815) - (6,815)
Shares repurchased - (32,815,783) (32,815,783)
Balance at December 31, 2018 526,031,092 (32,815,783) 493,215,309
Shares issued (a) (c) 2,716,349 18,773,958 21,490,307
Shares retired (6,106) - (6,106)
Shares repurchased - (27,001,399) (27,001,399)
Balance at December 31, 2019 528,741,335 (41,043,224) 487,698,111
Shares issued (a) 1,611,462 - 1,611,462
Shares retired (3,685) - (3,685)
Balance at December 31, 2020 530,349,112 (41,043,224) 489,305,888
____________
(a)Shares issued includes share awards granted to nonemployee directors.
(b)The year ended December 31, 2018 includes 94,409,573 shares issued in connection with the Merger (see Note 2).
(c)The year ended December 31, 2019 includes 18,773,958 treasury shares issued in connection with the settlement of all outstanding TEUs as discussed below.
Share Repurchase Programs
In September 2020, we announced that the Board authorized a new share repurchase program (Share Repurchase Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program was effective January 1, 2021, at which time the Prior Share Repurchase Plan (described below) and all authorized amounts remaining thereunder terminated as of such date.
Under the Share Repurchase Program, shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements.
In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding common stock may be purchased, and this authorized amount was fully utilized in 2018. In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase program (collectively, Prior Share Repurchase Program). The Prior Share Repurchase Program was terminated on January 1, 2021. Shares of common stock repurchased under the Prior Share Repurchase Program for the years ended December 31, 2020, 2019 and 2018 are reflected in the table below.
$500 Million Board Authorization $1.250 Billion Board Authorization
Total Number of Shares Repurchased Average Price Paid Share Amount Paid for Shares Repurchased Total Number of Shares Repurchased Average Price Paid Share Amount Paid for Shares Repurchased
Year Ended December 31, 2018 21,421,925 $ 23.36 $ 500 12,073,091 $ 22.99 $ 278
Year Ended December 31, 2019 - $ - $ - 26,322,166 $ 24.34 $ 640
Year Ended December 31, 2020 - - - - - -
Totals 21,421,925 $ 23.36 $ 500 38,395,257 $ 23.91 $ 918
Dividends
In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations.
In February 2019, May 2019, July 2019 and October 2019, the Board declared quarterly dividends of $0.125 per share that were paid in March 2019, June 2019, September 2019 and December 2019, respectively.
In February 2020, April 2020, July 2020 and October 2020, the Board declared quarterly dividends of $0.135 per share that were paid in March 2020, June 2020, September 2020 and December 2020, respectively.
In February 2021, the Board declared a quarterly dividend of $0.15 per share that will be paid in March 2021.
Vistra did not declare or pay any dividends during the year ended December 31, 2018.
Dividend Restrictions
The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2020, Vistra Operations can distribute approximately $6.7 billion to Parent under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $1.1 billion, $3.9 billion and $4.7 billion during the years ended December 31, 2020, 2019 and 2018, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2020, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled approximately $1.2 billion.
In addition to the restrictions under the Credit Facilities Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year.
Accumulated Other Comprehensive Income
During the years ended December 31, 2020, 2019 and 2018, we recorded changes in the funded status of our pension and other postretirement employee benefit liability totaling $23 million, $11 million and $9 million, respectively. During the years ended December 31, 2020, 2019 and 2018, $(5) million, $(3) million and $(3) million respectively was reclassified from accumulated other comprehensive income and reported in other deductions.
Warrants
At the Merger Date, the Company entered into an agreement whereby the holder of each outstanding warrant previously issued by Dynegy would be entitled to receive, upon paying an exercise, price of $35.00 (subject to adjustment from time to time), the number of shares of Vistra common stock that such holder would have been entitled to receive if it had held one share of Dynegy common stock at the closing of the Merger, or 0.652 shares of Vistra common stock. Accordingly, upon exercise, a warrant holder would effectively pay $53.68 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. As of December 31, 2020, nine million warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Merger Date.
Tangible Equity Units (TEUs)
At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% TEUs, each with a stated amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that delivered to the holder on July 1, 2019, 4.0813 shares of Vistra common stock per contract with cash paid in lieu of any fractional shares at a rate of $22.5954 per share and (ii) a senior amortizing note with an outstanding principal amount of $38 million at the Merger Date that paid an equal quarterly cash installment of $1.75 per amortizing note (see Note 11). In the aggregate, the annual quarterly cash installments were equivalent to a 7.00% cash payment per year with respect to each $100.00 stated amount of TEUs. The amortizing notes were accounted for as debt while the stock purchase contract was included in equity based on the fair value of the contract at the Merger Date (see note 11). The entire class of TEUs were suspended from trading on the New York Stock Exchange on July 1, 2019 and removed from listing and registration on July 12, 2019. On July 1, 2019, approximately 18.8 million treasury shares of Vistra common stock were issued in connection with the settlement of all outstanding TEUs.
15.FAIR VALUE MEASUREMENTS
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Chief Financial Officer.
Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 16 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
•Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that are legally characterized as settlement of derivative contracts rather than collateral.
•Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.
•Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company's risk management group.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement.
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
December 31, 2020 December 31, 2019
Level
1 Level
2 Level
3 (a) Reclass (b) Total Level
1 Level
2 Level
3 (a) Reclass (b) Total
Assets:
Commodity contracts $ 452 $ 201 $ 205 $ 76 $ 934 $ 1,047 $ 172 $ 239 $ 11 $ 1,469
Interest rate swaps - 72 - - 72 - - - - -
Nuclear decommissioning trust - equity securities (c) 623 - - - 623 564 - - - 564
Nuclear decommissioning trust - debt securities (c) - 618 - - 618 - 521 - - 521
Sub-total $ 1,075 $ 891 $ 205 $ 76 2,247 $ 1,611 $ 693 $ 239 $ 11 2,554
Assets measured at net asset value (d):
Nuclear decommissioning trust - equity securities (c) 433 366
Total assets $ 2,680 $ 2,920
Liabilities:
Commodity contracts $ 578 $ 172 $ 183 $ 76 $ 1,009 $ 985 $ 439 $ 313 $ 11 $ 1,748
Interest rate swaps - 404 - - 404 - 177 - - 177
Total liabilities $ 578 $ 576 $ 183 $ 76 $ 1,413 $ 985 $ 616 $ 313 $ 11 $ 1,925
____________
(a)See table below for description of Level 3 assets and liabilities.
(b)Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our consolidated balance sheets.
(c)The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note 21.
(d)The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.
Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 16 for further discussion regarding derivative instruments.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at December 31, 2020 and 2019:
December 31, 2020
Fair Value
Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b)
Electricity purchases and sales $ 61 $ (90) $ (29) Income Approach Hourly price curve shape (c) $ - to $ 85 $ 43
MWh
Illiquid delivery periods for hub power prices and heat rates (d) $ 25 to $ 125 $ 75
MWh
Options 38 (56) (18) Option Pricing Model Gas to power correlation (e) 30 % to 100 % 64 %
Power and gas volatility (e) 5 % to 665 % 336 %
Financial transmission rights 92 (16) 76 Market Approach (f) Illiquid price differences between settlement points (g) $ (5) to $ 50 $ 22
MWh
Other (h) 14 (21) (7)
Total $ 205 $ (183) $ 22
December 31, 2019
Fair Value
Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b)
Electricity purchases and sales $ 64 $ (53) $ 11 Income Approach Hourly price curve shape (c) $ - to $ 115 $ 58
MWh
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) $ 20 to $ 120 $ 70
MWh
Options 38 (188) (150) Option Pricing Model Gas to power correlation (e) 10 % to 100 % 55 %
Power and gas volatility (e) 5 % to 440 % 223 %
Financial transmission rights 120 (26) 94 Market Approach (f) Illiquid price differences between settlement points (g) $ (10) to $ 40 $ 15
MWh
Other (h) 17 (46) (29)
Total $ 239 $ (313) $ (74)
____________
(a)Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions. Options consist of physical electricity options, spread options, swaptions and natural gas options.
(b)The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.
(c)Primarily based on the historical range of forward average hourly ERCOT North Hub prices.
(d)Primarily based on historical forward ERCOT and PJM power prices and ERCOT heat rate variability.
(e)Primarily based on the historical forward correlation and volatility within ERCOT.
(f)While we use the market approach, there is insufficient market data to consider the valuation liquid.
(g)Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h)Other includes contracts for natural gas, coal and environmental allowances.
There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2020, 2019 and 2018. See the table below for discussion of transfers between Level 2 and Level 3 for the years ended December 31, 2020, 2019 and 2018.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the years ended December 31, 2020, 2019 and 2018.
Year Ended December 31,
2020 2019 2018
Net liability balance at beginning of period $ (74) $ (135) $ (53)
Total unrealized valuation gains (losses) (5) 8 (363)
Purchases, issuances and settlements (a):
Purchases 164 176 146
Issuances (28) (81) (41)
Settlements (90) (64) 76
Transfers into Level 3 (b) (2) 10 4
Transfers out of Level 3 (b) 57 12 133
Net liabilities assumed in connection with the Merger - - (37)
Net change (c) 96 61 (82)
Net asset (liability) balance at end of period $ 22 $ (74) $ (135)
Unrealized valuation gains (losses) relating to instruments held at end of period $ 18 $ (61) $ (174)
____________
(a)Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.
(b)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2020, transfers out of Level 3 primarily consist of gas, power and coal derivatives where forward pricing inputs have become observable. For the years ended December 31, 2019 and 2018, transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.
(c)Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our consolidated statements of operations.
16.COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 15 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity - We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets and to hedge future purchased power costs for our retail operations. We also utilize short-term electricity, natural gas, coal and emissions derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our consolidated statements of operations in operating revenues and fuel, purchased power costs and delivery fees.
Interest Rate Swaps - Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our consolidated statements of operations in interest expense and related charges. During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our consolidated balance sheets at December 31, 2020 and 2019. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
December 31, 2020
Derivative Assets Derivative Liabilities
Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total
Current assets $ 665 $ 19 $ 64 $ - $ 748
Noncurrent assets 197 53 8 - 258
Current liabilities (1) - (717) (71) (789)
Noncurrent liabilities (3) - (288) (333) (624)
Net assets (liabilities) $ 858 $ 72 $ (933) $ (404) $ (407)
December 31, 2019
Derivative Assets Derivative Liabilities
Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total
Current assets $ 1,323 $ - $ 10 $ - $ 1,333
Noncurrent assets 136 - - - 136
Current liabilities (1) - (1,510) (18) (1,529)
Noncurrent liabilities - - (237) (159) (396)
Net assets (liabilities) $ 1,458 $ - $ (1,737) $ (177) $ (456)
At December 31, 2020 and 2019, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.
Year Ended December 31,
Derivative (consolidated statements of operations presentation) 2020 2019 2018
Commodity contracts (Operating revenues) $ 241 $ 339 $ (855)
Commodity contracts (Fuel, purchased power costs and delivery fees) 4 (1) 18
Interest rate swaps (Interest expense and related charges) (196) (217) (11)
Net gain (loss) $ 49 $ 121 $ (848)
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.
Generally, margin deposits that contractually offset these derivative instruments are reported separately in our consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.
The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
December 31, 2020 December 31, 2019
Derivative Assets
and Liabilities Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative Assets
and Liabilities Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts
Derivative assets:
Commodity contracts $ 858 $ (667) $ (11) $ 180 $ 1,458 $ (1,113) $ - $ 345
Interest rate swaps 72 (72) - - - - - -
Total derivative assets 930 (739) (11) 180 1,458 (1,113) - 345
Derivative liabilities:
Commodity contracts (933) 667 138 (128) (1,737) 1,113 40 (584)
Interest rate swaps (404) 72 - (332) (177) - - (177)
Total derivative liabilities (1,337) 739 138 (460) (1,914) 1,113 40 (761)
Net amounts $ (407) $ - $ 127 $ (280) $ (456) $ - $ 40 $ (416)
____________
(a)Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at December 31, 2020 and 2019:
December 31, 2020 December 31, 2019
Derivative type Notional Volume Unit of Measure
Natural gas (a) 5,264 6,160 Million MMBtu
Electricity 438,863 428,367 GWh
Financial transmission rights (b) 217,350 199,648 GWh
Coal 20 22 Million U.S. tons
Fuel oil 176 33 Million gallons
Emissions 8 20 Million tons
Renewable energy certificates 18 11 Million certificates
Interest rate swaps - variable/fixed (c) $ 6,720 $ 6,720 Million U.S. dollars
Interest rate swaps - fixed/variable (c) $ 2,120 $ 2,120 Million U.S. dollars
____________
(a)Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.
(b)Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions.
(c)Includes notional amounts of interest rate swaps with maturity dates through July 2026.
Credit Risk-Related Contingent Features of Derivatives
Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
December 31,
2020 2019
Fair value of derivative contract liabilities (a) $ (679) $ (692)
Offsetting fair value under netting arrangements (b) 262 167
Cash collateral and letters of credit 35 67
Liquidity exposure $ (382) $ (458)
____________
(a)Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).
(b)Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At December 31, 2020, total credit risk exposure to all counterparties related to derivative contracts totaled $1.085 billion (including associated accounts receivable). The net exposure to those counterparties totaled $293 million at December 31, 2020 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $85 million. At December 31, 2020, the credit risk exposure to the banking and financial sector represented 65% of the total credit risk exposure and 18% of the net exposure.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
17.PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS
Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist entirely of participants who were active and retired collective bargaining unit employees. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations.
Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.
Prior to the Merger, Dynegy provided pension and OPEB benefits to certain of its employees and retirees. At the Merger Date, Vistra assumed these plans and the excess of the benefit obligations over the fair value of plan assets was recognized as a liability (see Note 2). Benefit obligations assumed totaled $539 million and the fair value of plan assets assumed totaled $459 million, and the net unfunded liability was recorded as $15 million to other noncurrent assets, $2 million to other current liabilities and $93 million to other noncurrent liabilities in the consolidated balance sheets.
Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts for its interest in this OPEB plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the OPEB information presented below. In addition, Vistra is the sponsor of OPEB plans that certain EFH Corp. and Dynegy retirees participate in.
Pension and OPEB Costs
Year Ended December 31,
2020 2019 2018
Pension costs $ 11 $ 9 $ 14
OPEB costs 7 11 9
Total benefit costs recognized as expense $ 18 $ 20 $ 23
Market-Related Value of Assets Held in Pension Benefit Trusts
We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
Detailed Information Regarding Pension Benefits
The following information is based on a December 31, 2020, 2019 and 2018 measurement dates:
Year Ended December 31,
2020 2019 2018
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate (Vistra Plan) 3.24 % 4.37 % 3.74 %
Discount rate (Dynegy Plan and EEI Plan) 3.24 % 4.37 % 4.05 %
Expected return on plan assets (Vistra Plan) 4.44 % 4.80 % 4.56 %
Expected return on plan assets (Dynegy Plan) 5.28 % 5.31 % 5.94 %
Expected return on plan assets (EEI Plan) 5.45 % 5.56 % 4.74 %
Expected rate of compensation increase (Vistra Plan) 3.29 % 3.35 % 3.62 %
Expected rate of compensation increase (Dynegy Plan and EEI Plan) 3.29 % 3.35 % 3.50 %
Interest crediting rate for cash balance plans (Vistra Plan) 3.50 % 3.50 % 3.50 %
Interest crediting rate for cash balance plans (Dynegy Plan and EEI Plan) 3.50 % 3.50 % 4.25 %
Components of Net Pension Cost:
Service cost $ 6 $ 7 $ 15
Interest cost 20 25 21
Expected return on assets (23) (26) (23)
Amortization of unrecognized amounts 1 - -
Immediate pension cost 7 3 1
Net periodic pension cost $ 11 $ 9 $ 14
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss $ 17 $ 11 $ 14
Total recognized in net periodic benefit cost and other comprehensive income $ 28 $ 20 $ 28
Assumptions Used to Determine Benefit Obligations:
Discount rate 2.50 % 3.24 % 4.37 %
Expected rate of compensation increase 3.41 % 3.29 % 3.35 %
Interest crediting rate for cash balance plans 3.00 % 3.50 % 3.50 %
For the year ended December 31, 2020, the net actuarial loss of $29 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect current market conditions and plan amendments, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy updates, annuity purchases, lump sum windows and plan experience different than expected.
For the year ended December 31, 2019, the net actuarial loss of $16 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect current market conditions, annuity purchases, plan amendments and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations and life expectancy updates.
For the year ended December 31, 2018, the net actuarial loss of $14 million was driven by losses attributable to actual asset performance falling short of expectations and plan experience different than expected, partially offset by gains attributable to increasing discount rates due to changes in the corporate bond markets, economic assumption updates to reflect current market conditions and life expectancy projection updates.
Year Ended December 31,
2020 2019
Change in Pension Obligation:
Projected benefit obligation at beginning of period $ 674 $ 615
Service cost 6 7
Interest cost 20 25
Lump-sum window (6) -
Annuity purchase (29) (18)
Actuarial loss 46 93
Benefits paid (68) (48)
Projected benefit obligation at end of year $ 643 $ 674
Accumulated benefit obligation at end of year $ 639 $ 669
Change in Plan Assets:
Fair value of assets at beginning of period $ 528 $ 490
Employer contributions 16 -
Lump-sum window (6) -
Annuity purchase (29) (18)
Actual gain on assets 40 102
Benefits paid (64) (46)
Fair value of assets at end of year $ 485 $ 528
Funded Status:
Projected pension benefit obligation $ (643) $ (674)
Fair value of assets 485 528
Funded status at end of year $ (158) $ (146)
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent liabilities $ (158) $ (146)
Net liability recognized $ (158) $ (146)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net (loss) $ (42) $ (24)
The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.
December 31,
2020 2019
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations $ 643 $ 674
Accumulated benefit obligation $ 639 $ 669
Plan assets $ 485 $ 528
Pension Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets. Real estate and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.
The target asset allocation ranges of pension plan investments by asset category are as follows:
Target Allocation Ranges
Asset Category: Vistra Plan Dynegy Plan EEI Plan
Fixed income 65 % - 75% 45 % - 55% 40 % - 50%
Global equity securities 16 % - 24% 30 % - 38% 34 % - 42%
Real estate 4 % - 8% 8 % - 12% 10 % - 14%
Credit strategies 3 % - 7% 6 % - 10% 7 % - 11%
Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Retirement Plan
Expected Long-Term Rate of Return
Asset Class: Vistra Plan Dynegy Plan EEI Plan
Fixed income securities 2.4 % 2.3 % 2.3 %
Global equity securities 7.3 % 7.3 % 7.3 %
Real estate 5.6 % 5.6 % 5.6 %
Credit strategies 4.8 % 4.8 % 4.8 %
Weighted average 3.8 % 4.4 % 4.7 %
Fair Value Measurement of Pension Plan Assets
At December 31, 2020 and 2019, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) and consisted of the following:
Year Ended December 31,
2020 2019
Asset Category:
Cash commingled trusts 11 10
Equity securities:
Global equities 153 169
Fixed income securities:
Corporate bonds (a) 207 211
Government bonds 37 50
Other (b) 32 37
Real estate 45 51
Total assets measured at net asset value $ 485 $ 528
___________
(a)Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.
(b)Consists primarily of high-yield bonds, emerging market debt and bank loans.
Detailed Information Regarding Postretirement Benefits Other Than Pensions
The following OPEB information is based on a December 31, 2020 measurement date:
Year Ended December 31,
2020 2019 2018
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate (Vistra Plan) 3.25 % 4.35 % 3.67 %
Discount rate (Split-Participant Plan) 3.25 % 4.35 % 3.67 %
Discount rate (Dynegy Plan) 3.25 % 4.35 % 4.04 %
Expected return on plan assets (EEI Union) 7.07 % 5.36 % 5.10 %
Expected return on plan assets (EEI Salaried) 3.43 % 4.70 % 4.47 %
Components of Net Postretirement Benefit Cost:
Service cost $ 2 $ 2 $ 2
Interest cost 4 6 5
Expected return on plan assets (2) (1) (1)
Amortization of unrecognized amounts 4 3 3
Immediate postretirement benefit cost (1) 1 -
Net periodic OPEB cost $ 7 $ 11 $ 9
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss and prior service (credit) cost $ 5 $ - $ (6)
Total recognized in net periodic benefit cost and other comprehensive income $ 12 $ 11 $ 3
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate 2.51 % 3.25 % 4.35 %
For the year ended December 31, 2020, the net actuarial loss of $10 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy updates and updates to health care claims and trend assumptions.
For the year ended December 31, 2019, the net actuarial loss of $5 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy changes, updates to health care related assumptions and changes due to the repeal of certain Affordable Care Act fees.
For the period ended December 31, 2018, the net actuarial loss of $7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, life expectancy projection updates and updates to health care related assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and plan experience different than expected.
Year Ended December 31,
2020 2019
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year $ 151 $ 144
Service cost 2 2
Interest cost 4 6
Participant contributions 3 3
Actuarial loss 12 10
Benefits paid (15) (14)
Benefit obligation at end of year $ 157 $ 151
Change in Plan Assets:
Fair value of assets at beginning of year $ 34 $ 29
Employer contributions 9 9
Participant contributions 3 3
Benefits paid (13) (13)
Actual gain on assets 4 6
Fair value of assets at end of year $ 37 $ 34
Funded Status:
Benefit obligation $ (157) $ (151)
Fair value of assets 37 34
Funded status at end of year $ (120) $ (117)
Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent assets $ 23 $ 18
Other current liabilities $ (9) $ (9)
Other noncurrent liabilities (134) (126)
Net liability recognized $ (120) $ (117)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss and prior service cost $ 20 $ 15
The following tables provide information regarding the assumed health care cost trend rates.
December 31, 2020 December 31, 2019
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year 6.20 % 6.40 %
Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 %
Year that the rate reaches the ultimate trend rate 2029 2029
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year (Vistra Plan, EEI Union and EEI Salaried) 9.10 % 8.60 %
Health care cost trend rate assumed for next year (Split-Participant Plan) 8.80 % 8.30 %
Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 %
Year that the rate reaches the ultimate trend rate 2030 2029
Fair Value Measurement of OPEB Plan Assets
At December 31, 2020 and 2019, the Vistra OPEB plan assets measured at fair value on a recurring basis totaled $37 million and $34 million, respectively, and consisted of $29 million and $26 million, respectively, of U.S. equities classified as Level 1 and $8 million and $8 million, respectively, of U.S. Treasuries and municipal bonds classified as Level 2.
Significant Concentrations of Risk
The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2020 consisted of 305 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings.
Contributions
Contributions to the Retirement Plan for the years ended December 31, 2020, 2019 and 2018 totaled $16 million, zero and $12 million, respectively, and $1 million in contributions are expected to be made in 2021. OPEB plan funding for the years ended December 31, 2020, 2019 and 2018 totaled $9 million, $9 million and $8 million, respectively, and funding in 2021 is expected to total $9 million.
Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
2021 2022 2023 2024 2025 2026-2030
Pension benefits $ 49 $ 43 $ 43 $ 40 $ 52 $ 188
OPEB $ 10 $ 10 $ 10 $ 10 $ 9 $ 41
Qualified Savings Plans
Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the traditional formula in the Retirement Plan) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.
At the Merger Date, Vistra assumed Dynegy's participant-directed defined contribution plan. In January 2019, this plan was merged into the Thrift Plan.
Aggregate employer contributions to the qualified savings plans totaled $34 million, $27 million and $24 million for the years ended December 31, 2020, 2019 and 2018, respectively.
18.STOCK-BASED COMPENSATION
Vistra 2016 Omnibus Incentive Plan
On the Effective Date, the Vistra board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019 annual meeting of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards.
If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date.
As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders.
Assumption of Dynegy Stock Compensation Plans
At the Merger Date, Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra's common stock, after giving effect to the Exchange Ratio.
Instrument Type Dynegy Awards Prior to the Merger Date Vistra Awards Converted at the Merger Date Fair Value of Awards (a) at the Merger Date
Stock Options 4,096,027 2,670,610 $ 10
Restricted Stock Units 5,718,148 3,056,689 61
Performance Units 1,538,133 938,721 18
Total $ 89
____________
(a)$26 million was attributable to pre-combination service and considered part of the purchase price (see Note 2). $33 million was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger. $30 million will be amortized as compensation expense over the remaining service period and is recorded in additional paid in capital in the consolidated balance sheet.
Stock-Based Compensation Expense
Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows:
Year Ended December 31,
2020 2019 2018
Total stock-based compensation expense $ 63 $ 47 $ 73
Income tax benefit (15) (9) (15)
Stock based-compensation expense, net of tax $ 48 $ 38 $ 58
Stock Options
The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model. The risk-free interest rate used in the option valuation model was based on yields available on the grant dates for U.S. Treasury Strips with maturity consistent with the expected life assumption. The expected term of the option represents the period of time that options granted are expected to be outstanding and is based on the SEC Simplified Method (midpoint of average vesting time and contractual term). Expected volatility is based on an average of the historical, daily volatility of a peer group selected by Vistra over a period consistent with the expected life assumption ending on the grant date. We assumed no dividend yield in the valuation of the options granted from 2016 through 2018, and assumed 2.3% and 1.9% dividend yields in the valuation of options granted in 2020 and 2019, respectively. These options may be exercised over either three- or four-year graded vesting periods and will expire 10 years from the grant date.
Issuance of Merger-related Stock Options - At the Merger Date, we issued 5.2 million stock options to certain members of management, which are subject to performance and service conditions for vesting. The performance condition is based on the Company's achievement of certain merger related targets which were achieved as of December 31, 2019. Compensation cost was recognized in 2018, 2019 and 2020 based on graded vesting over 4 and 5 years since the date of issuance because we estimated achievement of the target was likely to occur.
Stock options outstanding at December 31, 2020 are all held by current or former employees. The following table summarizes our stock option activity:
Year Ended December 31, 2020
Stock Options
(in thousands) Weighted
Average Exercise Price Weighted Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period 13,535 $ 18.73 7.3 $ 69.3
Granted 3,014 $ 22.98
Exercised (251) $ 13.62
Forfeited or expired (268) $ 20.74
Total outstanding at end of period 16,030 $ 19.58 6.7 $ 30.8
Exercisable at December 31, 2020 6,871 $ 16.83 5.9 $ 30.5
At December 31, 2020, $27 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years.
Restricted Stock Units
The following table summarizes our restricted stock unit activity:
Year Ended December 31, 2020
Restricted Stock Units
(in thousands) Weighted
Average Grant Date Fair Value
Total nonvested at beginning of period 2,538 $ 20.99
Granted 1,209 $ 22.50
Vested (1,456) $ 19.48
Forfeited (39) $ 21.89
Total nonvested at end of period 2,252 $ 22.35
At December 31, 2020, $27 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years.
Performance Stock Units
In October 2017, February 2019 and February 2020, we issued Performance Stock Units (PSUs) to certain members of management. All PSUs have a three years performance period and a payout opportunity of 0-200% of target (100%), which is intended to be settled in shares of Vistra common stock. As of December 31, 2019, we had not yet established the final terms of the previously issued PSUs relevant to vesting (scorecard, thresholds, and targets) for the entire measurement period; therefore, a grant date for financial accounting purposes had not occurred. In February 2020, the final terms were established for the October 2017 issuance and a grant date for financial accounting purposes had occurred. In March 2020, we began recognizing compensation cost ratably over the remaining 13-month vesting period for the October 2017 issuance. In February 2021, the final terms were established for the February 2019 issuance and a grant date for financial accounting purposes has occurred. In March 2021, we will begin recognizing compensation cost ratably over the remaining 12-month vesting period for the February 2019 issuance. Additional PSUs were issued to certain members of management in February 2021 with the grant date for accounting purposes not yet established. The following table summarizes our PSU activity:
Year Ended December 31, 2020
Performance Stock Units
(in thousands) Weighted
Average Grant Date Fair Value
Total nonvested at beginning of period - $ -
Granted 473 $ 23.43
Vested (21) $ 23.43
Forfeited (1) $ 23.43
Total nonvested at end of period 451 $ 23.43
At December 31, 2020, $4 million of unrecognized compensation cost related to unvested performance stock units granted under the 2016 Incentive Plan is expected to be recognized over a weighted average period of approximately 3 months.
19.RELATED PARTY TRANSACTIONS
In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra common stock held by such selling stockholders.
In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra common stock held by certain significant stockholders pursuant to the Registration Rights Agreement, which was declared effective by the SEC in May 2017. The registration statement was amended in March 2018. Pursuant to the Registration Rights Agreement, in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on Form S-3, which was declared effective by the SEC in July 2018. Among other things, under the terms of the Registration Rights Agreement:
•if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and
•the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration (as defined in the Registration Rights Agreement) and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed.
All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us. Legal fee expenses paid or accrued by Vistra on behalf of the selling stockholders totaled less than $1 million during each of the years ended December 31, 2020, 2019 and 2018.
Tax Receivable Agreement
On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH. See Note 8 for discussion of the TRA.
Share Repurchase Transaction
In November 2018, the disinterested members of the Board considered and approved (in accordance with the Company's corporate governance guidelines) a share repurchase transaction, whereby Apollo Management Holdings L.P. (Apollo) and the Company, in a privately negotiated transaction, agreed for the Company to directly repurchase 5 million of Vistra common shares from Apollo. This purchase was part of Apollo's larger, 17 million share block trade, with the remaining 12 million shares being sold in a separate unregistered Rule 144 secondary block trade to a broker-dealer, who placed all 12 million shares with institutional investors. The Company repurchased the 5 million shares at the same discounted price (discounted from the November 19, 2018 closing price) that the participating broker paid for the 12 million shares it purchased, and the Company did not pay any additional fees to Apollo or the participating broker for the 5 million shares it repurchased.
20.SEGMENT INFORMATION
The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. Management believes the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The following is a summary of the updated segments:
•The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments. As we announced significant plant closures in the third quarter of 2020, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.
•The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes operations in PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.
•The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporate and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 3), the Company expects to expand its operations in the West segment.
Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources.
The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 states in the U.S.
The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management. The Texas segment represents results from the ERCOT market and was referred to as the ERCOT segment prior to the third quarter of 2020. The East segment represents results from the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics.
The West segment represents results from the CAISO market, including our development of battery ESS projects at our Moss Landing and Oakland power plant sites (see Note 3).
The Sunset segment consists of generation plants with announced retirement plans. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement plans.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 4). Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. We have not allocated any unrealized gains or losses on the commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018, 2019 and 2020.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating segments.
Except as noted in Note 1, the accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on U.S. GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments.
For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other (b) Eliminations Consolidated
Operating revenues (a):
December 31, 2020 $ 8,270 $ 4,116 $ 2,415 $ 282 $ 1,252 $ 3 $ - $ (4,895) $ 11,443
December 31, 2019 6,872 3,836 2,790 338 1,602 341 - (3,970) 11,809
December 31, 2018 5,597 2,497 1,895 208 1,183 371 - (2,607) 9,144
Depreciation and amortization:
December 31, 2020 $ (303) $ (475) $ (721) $ (19) $ (133) $ (22) $ (64) $ - $ (1,737)
December 31, 2019 (292) (472) (680) (19) (120) - (57) - (1,640)
December 31, 2018 (318) (390) (519) (14) (81) - (72) - (1,394)
Operating income (loss):
December 31, 2020 $ 312 $ 1,761 $ 73 $ 39 $ (420) $ (109) $ (137) $ - $ 1,519
December 31, 2019 155 1,314 398 88 271 (107) (127) 1 1,993
December 31, 2018 690 (103) 10 35 242 (63) (320) - 491
Interest expense and related charges:
December 31, 2020 $ (10) $ 8 $ (7) $ 10 $ (2) $ - $ (632) $ 3 $ (630)
December 31, 2019 (21) 8 (13) - (4) - (770) 3 (797)
December 31, 2018 (7) (12) (10) (1) (1) - (612) 71 (572)
Income tax (expense) benefit:
December 31, 2020 $ - $ - $ - $ - $ - $ - $ (266) $ - $ (266)
December 31, 2019 - - - - - - (290) - (290)
December 31, 2018 - - - - - - 45 - 45
Net income (loss):
December 31, 2020 $ 309 $ 1,760 $ 41 $ 50 $ (414) $ (101) $ (1,021) $ - $ 624
December 31, 2019 134 1,342 400 88 274 (109) (1,204) 1 926
December 31, 2018 712 (88) 18 34 242 (62) (912) - (56)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
December 31, 2020 $ 2 $ 388 $ 71 $ 2 $ 46 $ - $ 91 $ - $ 600
December 31, 2019 1 296 61 2 58 - 69 - 487
December 31, 2018 1 280 21 8 36 - 50 - 396
____________
(a)The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:
For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated
December 31, 2020 $ (11) $ 677 $ (23) $ (10) $ (140) $ - $ - $ (329) $ 164
December 31, 2019 8 575 195 41 168 - - (305) 682
December 31, 2018 (12) (483) (76) (15) (11) - - 217 (380)
____________
(1) Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(b)Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate and Other net income.
21.SUPPLEMENTARY FINANCIAL INFORMATION
Impairment of Long-Lived Assets
In the third quarter of 2020, we recognized impairment losses of $173 million related to our Kincaid coal generation facility in Illinois and $99 million related to our Zimmer coal generation facility in Ohio, each as a result of a significant decrease in the estimated useful life of the facility, reflecting our recently announced plan to retire both facilities by the end of 2027 in response to the final CCR rule (see Notes 4 and 13). The impairment losses are reported in our Sunset segment and include a $260 million write-down of property, plant and equipment and a $12 million write-down of inventory. In determining the fair value of the impaired assets, we equally weighted a market approach valuation based on transactions of similar assets and an income approach valuation discounting our projected cash flows through the respective plant retirement dates.
In the first quarter of 2020, we recognized an impairment loss of $52 million related to our Joppa/EEI coal generation facility in Illinois as a result of a significant decrease in the estimated useful life of the facility, reflecting a decrease in the economic forecast of the facility and changes to the operating assumption based on lower forecasted wholesale electricity prices. We also recorded a $32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facility and therefore determined to have a significant decrease in estimated useful life. The impairments are reported in our Sunset segment and include a $45 million write-down of property, plant and equipment, a $32 million write-down of intangible assets and a $7 million write-down of inventory.
Interest Expense and Related Charges
Year Ended December 31,
2020 2019 2018
Interest paid/accrued $ 467 $ 576 $ 537
Unrealized mark-to-market net losses on interest rate swaps 155 220 5
Amortization of debt issuance costs, discounts and premiums 18 9 -
Debt extinguishment (gain) loss (17) (21) 27
Capitalized interest (21) (12) (12)
Other 28 25 15
Total interest expense and related charges $ 630 $ 797 $ 572
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 3.88%, 4.03% and 4.24% at December 31, 2020, 2019 and 2018, respectively.
Other Income and Deductions
Year Ended December 31,
2020 2019 2018
Other income:
Insurance settlement (a) $ 6 $ 22 $ 16
Funds released from escrow to settle pre-petition claims of our predecessor (b) - 9 -
Office space sublease rental income (b) - - 8
Sale of land (c) 8 - 3
Interest income 2 10 18
All other 18 15 2
Total other income $ 34 $ 56 $ 47
Other deductions:
Loss on disposal of investment in NELP (d) $ 29 $ - $ -
All other 13 15 5
Total other deductions $ 42 $ 15 $ 5
____________
(a)For the year ended December 31, 2020, $3 million reported in the Corporate and Other non-segment, $2 million reported in the Asset Closure segment and $1 million reported in the Texas segment. The amounts for the years ended December 31, 2019 and 2018, respectively, are reported in the Texas segment.
(b)Reported in the Corporate and Other non-segment. Beginning January 1, 2019, our office space sublease rental income related to real estate leases is reported in SG&A expenses in the consolidated statements of operations.
(c)For the year ended December 31, 2020, reported in the Asset Closure segment. For the year ended December 31, 2018, reported in the Texas segment.
(d)Reported in the East segment.
Restricted Cash
December 31, 2020 December 31, 2019
Current
Assets Noncurrent Assets Current
Assets Noncurrent Assets
Amounts related to remediation escrow accounts $ 19 $ 19 $ 15 $ 28
Amounts related to restructuring escrow accounts - - 43 -
Amounts related to Ambit customer deposits - - 19 -
Amounts related to Ambit commodity trading agreement - - 62 -
Amounts related to Ambit letters of credit (Note 11) - - 8 -
Total restricted cash $ 19 $ 19 $ 147 $ 28
Remediation Escrow - During the years ended December 31, 2020 and 2019, Vistra transferred asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra deposits funds into an escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.
Pre-Petition Claims - On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged approximately $33.8 billion in liabilities subject to compromise. Initial distributions related to the allowed claims asserted against the TCEH Debtors and the Contributed EFH Debtors commenced subsequent to the Effective Date. Amounts were held in escrow to (1) distribute to holders of contingent and/or disputed unsecured claims that become allowed and/or (2) make distributions to holders of previously allowed unsecured claims, if applicable. In December 2019, the Bankruptcy Court entered an order, Docket No. 13982, sustaining the TCEH Debtors' objection to and liquidating the manifested and unmanifested asbestos claims. As of this filing, the TCEH Debtors believe they have resolved the remaining contingent and/or disputed unsecured claims, and have undertook the necessary steps to modify the claims register accordingly and made final distribution from the escrow to holders of allowed claims. At December 31, 2019, unresolved claims were recorded in Vistra's consolidated balance sheet as other current liabilities, and the related escrow balance were recorded in Vistra's consolidated balance sheet as current restricted cash. All non-priority unsecured claims, including asbestos claims arising before the Petition Date, were satisfied solely from the amounts in escrow.
Trade Accounts Receivable
December 31,
2020 2019
Wholesale and retail trade accounts receivable $ 1,324 $ 1,401
Allowance for uncollectible accounts (45) (36)
Trade accounts receivable - net $ 1,279 $ 1,365
Gross trade accounts receivable at December 31, 2020 and 2019 included unbilled retail revenues of $468 million and $494 million, respectively.
Allowance for Uncollectible Accounts Receivable
Year Ended December 31,
2020 2019 2018
Allowance for uncollectible accounts receivable at beginning of period (a) $ 42 $ 19 $ 14
Increase for bad debt expense 110 82 56
Decrease for account write-offs (107) (65) (51)
Allowance for uncollectible accounts receivable at end of period $ 45 $ 36 $ 19
____________
(a)Includes a $6 million increase recorded due to the adoption of ASU 2016-13, Financial Instruments-Credit Losses (see Note 1).
Inventories by Major Category
December 31,
2020 2019
Materials and supplies $ 260 $ 278
Fuel stock 236 172
Natural gas in storage 19 19
Total inventories $ 515 $ 469
Investments
December 31,
2020 2019
Nuclear plant decommissioning trust $ 1,674 $ 1,451
Assets related to employee benefit plans (Note 17) 41 37
Land 44 49
Total investments $ 1,759 $ 1,537
Investment in Unconsolidated Subsidiary
On the Merger Date, we assumed Dynegy's 50% interest in NELP, a joint venture with NextEra Energy, Inc., which indirectly owned the Bellingham NEA facility and the Sayreville facility. At December 31, 2019, our investment in NELP totaled $123 million.
In December 2019, Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., indirect subsidiaries of Vistra, entered into a transaction agreement with NELP and certain indirect subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP in exchange for 100% ownership interest in NJEA, the company which owns the Sayreville facility. The NELP Transaction was approved by FERC in February 2020, and the NELP Transaction closed on March 2, 2020. As a result of the NELP Transaction, Vistra indirectly owns 100% of the Sayreville facility and no longer has any ownership interest in the Bellingham NEA facility. A loss of $29 million was recognized in connection with the NELP Transaction, reflecting the difference between our derecognized investment in NELP and the value of our acquired 100% interest in NJEA, which was measured in accordance with ASC 805. The loss is reported in our consolidated statements of operations in other deductions.
Equity earnings related to our investment in NELP totaled $3 million, $14 million and $17 million for the years ended December 31, 2020, 2019 and 2018, respectively, recorded in equity in earnings of unconsolidated investment in our consolidated statements of operations. We received distributions totaling $3 million, $22 million and $17 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Nuclear Decommissioning Trust
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability, are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra, provided that Vistra complied with PUCT rules and regulations regarding decommissioning trusts. A summary of the fair market value of investments in the fund follows:
Year Ended December 31,
2020 2019
Debt securities (a) $ 618 $ 521
Equity securities (b) 1,056 930
Total $ 1,674 $ 1,451
____________
(a)The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 2.91% and 3.42% at December 31, 2020 and 2019, respectively, and an average maturity of 10 years and 9 years at December 31, 2020 and 2019, respectively.
(b)The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments.
Debt securities held at December 31, 2020 mature as follows: $193 million in one to five years, $185 million in five to 10 years and $240 million after 10 years.
The following table summarizes proceeds from sales of securities and investments in new securities.
Year Ended December 31,
2020 2019 2018
Proceeds from sales of securities $ 433 $ 431 $ 252
Investments in securities $ (455) $ (453) $ (274)
Property, Plant and Equipment
December 31,
2020 2019
Power generation and structures $ 15,222 $ 15,205
Land 617 622
Office and other equipment 173 164
Total 16,012 15,991
Less accumulated depreciation (3,614) (2,553)
Net of accumulated depreciation 12,398 13,438
Finance lease right-of-use assets (net of accumulated depreciation) 182 59
Nuclear fuel (net of accumulated amortization of $91 million and $216 million)
207 197
Construction work in progress 712 220
Property, plant and equipment - net $ 13,499 $ 13,914
Depreciation expenses totaled $1.377 billion, $1.300 billion and $1.024 billion for the years ended December 31, 2020, 2019 and 2018, respectively.
Our property, plant and equipment consist of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful lives range from 1 to 33 years for our property, plant and equipment.
Asset Retirement and Mining Reclamation Obligations (ARO)
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor. We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets. However, because the period of remediation is indeterminable no removal liabilities have been recognized.
At December 31, 2020, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.585 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our consolidated balance sheet of $89 million in other noncurrent liabilities and deferred credits.
The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our consolidated balance sheets, for the years ended December 31, 2020, 2019 and 2018:
Nuclear Plant Decommissioning Mining Land Reclamation Coal Ash and Other Total
Liability at December 31, 2017 $ 1,233 $ 438 $ 265 $ 1,936
Additions:
Accretion 43 22 28 93
Adjustment for change in estimates - 56 (89) (33)
Obligations assumed in the Merger - 2 475 477
Reductions:
Payments - (76) (24) (100)
Liability at December 31, 2018 1,276 442 655 2,373
Additions:
Accretion 44 22 31 97
Adjustment for change in estimates - 16 (1) 15
Adjustment for obligations assumed through acquisitions - - (3) (3)
Reductions:
Payments - (70) (39) (109)
Liability transfers (a) - - (135) (135)
Liability at December 31, 2019 1,320 410 508 2,238
Additions:
Accretion 46 20 23 89
Adjustment for change in estimates (b) 219 (6) 25 238
Reductions:
Payments - (65) (49) (114)
Liability transfers (a) - - (15) (15)
Liability at December 31, 2020 1,585 359 492 2,436
Less amounts due currently - (92) (11) (103)
Noncurrent liability at December 31, 2020 $ 1,585 $ 267 $ 481 $ 2,333
____________
(a)Represents ARO transferred to a third-party for remediation. Any remaining unpaid third-party obligation has been reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.
(b)The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2020. Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occur, and the PUCT requires a new cost estimate at least every five years. The increase in the liability was driven by changes in assumptions including increased costs for labor, equipment and services and a delay in timing of when the U.S. Department of Energy is estimated to begin accepting spent fuel offsite.
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
December 31,
2020 2019
Retirement and other employee benefits (Note 17) $ 312 $ 295
Identifiable intangible liabilities (Note 6) 289 286
Regulatory liability 89 131
Finance lease liabilities 206 78
Uncertain tax positions, including accrued interest 12 10
Liability for third-party remediation 31 41
Environmental allowances - 52
Accrued severance costs 54 12
Other accrued expenses 138 84
Total other noncurrent liabilities and deferred credits $ 1,131 $ 989
Fair Value of Debt
December 31, 2020 December 31, 2019
Long-term debt (see Note 11): Fair Value Hierarchy Carrying Amount Fair
Value Carrying Amount Fair
Value
Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,579 $ 2,565 $ 2,715 $ 2,717
Vistra Operations Senior Notes Level 2 6,634 7,204 6,620 6,926
Vistra Senior Notes Level 2 - - 774 772
Forward Capacity Agreements Level 3 45 45 155 155
Equipment Financing Agreements Level 3 59 59 87 87
Building Financing Level 2 10 10 16 16
Other debt Level 3 3 3 12 12
We determine fair value in accordance with accounting standards as discussed in Note 15. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.
Supplemental Cash Flow Information
The following table reconciles cash, cash equivalents and restricted cash reported in our consolidated statements of cash flows to the amounts reported in our consolidated balance sheets at December 31, 2020 and 2019:
December 31,
2020 2019
Cash and cash equivalents $ 406 $ 300
Restricted cash included in current assets 19 147
Restricted cash included in noncurrent assets 19 28
Total cash, cash equivalents and restricted cash $ 444 $ 475
The following table summarizes our supplemental cash flow information for the years ended December 31, 2020, 2019 and 2018, respectively.
Year Ended December 31,
2020 2019 2018
Cash payments related to:
Interest paid $ 503 $ 525 $ 651
Capitalized interest (21) (12) (12)
Interest paid (net of capitalized interest) $ 482 $ 513 $ 639
Income taxes paid / (refunds received) (a) $ (140) $ (76) $ 67
Noncash investing and financing activities:
Accrued property, plant and equipment additions (b) $ 19 $ 67 $ 84
Disposition of investment in NELP $ 123 $ - $ -
Acquisition of investment in NJEA $ 90 $ - $ -
Shares issued for tangible equity unit contracts (Note 14) $ - $ 446 $ -
Land transferred with liability transfers $ - $ 16 $ -
Vistra common stock issued in the Merger (Notes 2 and 14) $ - $ - $ 2,245
____________
(a)For the years ended December 31, 2020, 2019 and 2018, we paid federal income taxes of zero, zero and $45 million, respectively, paid state income taxes of $40 million, $42 million and $27 million, respectively, received federal tax refunds of $170 million, $115 million and zero, respectively, and received state tax refunds of $10 million, $3 million and $5 million, respectively.
(b)Represents property, plant and equipment accruals during the period for which cash has not been paid as of the end of the period.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A.CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at December 31, 2020. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective as of that date.
There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
VISTRA CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Vistra Corp. is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.
The management of Vistra Corp. performed an evaluation of the effectiveness of the company's internal control over financial reporting as of December 31, 2020 based on the Committee of Sponsoring Organizations of the Treadway Commission's (COSO's) Internal Control - Integrated Framework (2013). Based on the review performed, management believes that as of December 31, 2020 Vistra Corp.'s internal control over financial reporting was effective.
The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Vistra Corp. has issued an attestation report on Vistra Corp.'s internal control over financial reporting.
/s/ CURTIS A. MORGAN /s/ JAMES A. BURKE
Curtis A. Morgan James A. Burke
Chief Executive Officer President and Chief Financial Officer
(Principal Executive Officer) (Principal Financial Officer)
February 26, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Vistra Corp.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Vistra Corp. and its subsidiaries (the "Company") 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 (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 26, 2021, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 26, 2021

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ITEM 9B. OTHER INFORMATION
Item 9B.OTHER INFORMATION
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Code of Ethics
Vistra has adopted a code of ethics entitled "Vistra Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of Vistra. It may be accessed through the "Corporate Governance" section of the Company's website at www.vistracorp.com. Vistra also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website and will disclose such events within four business days following the date of the amendment or waiver, and such information will remain available on this website for at least a 12-month period. A copy of the "Vistra Code of Conduct" is available in print to any stockholder who requests it.
Other information required by this Item is incorporated by reference to the similarly named section of Vistra Definitive Proxy Statement for its 2021 Annual Meeting of Stockholders.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.EXECUTIVE COMPENSATION
Information required by this Item is incorporated by reference to the similarly named section of Vistra's Definitive Proxy Statement for its 2021 Annual Meeting of Stockholders.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this Item is incorporated by reference to the sections entitled "Beneficial Ownership of Common Stock of the Company" in Vistra's Definitive Proxy Statement for its 2021 Annual Meeting of Stockholders.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by this Item is incorporated by reference to the sections entitled "Business Relationships and Related Person Transactions Policy" and "Director Independence" in Vistra's Definitive Proxy Statement for its 2021 Annual Meeting of Stockholders.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by this Item is incorporated by reference to the sections entitled "Principal Accounting Fees" in Vistra's Definitive Proxy Statement for its 2021 Annual Meeting of Stockholders.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this annual report on Form 10-K.
(b) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS
(Millions of Dollars)
Year Ended December 31,
2020 2019 2018
Depreciation and amortization $ (15) $ (7) $ -
Selling, general and administrative expenses (72) (62) (266)
Operating loss (87) (69) (266)
Other income 5 12 9
Interest expense and related charges (7) (88) (257)
Impacts of Tax Receivable Agreement 5 (37) (79)
Loss before income tax benefit (84) (182) (593)
Income tax benefit 25 42 282
Equity in earnings of subsidiaries, net of tax 695 1,068 257
Net income (loss) $ 636 $ 928 $ (54)
See Notes to the Condensed Financial Statements.
VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
2020 2019 2018
Cash flows - operating activities:
Cash used in operating activities $ (86) $ (58) $ (125)
Cash flows - investing activities:
Capital expenditures (15) (36) (24)
Dividend received from subsidiaries 1,105 3,890 4,668
Other, net - - (1)
Cash provided by investing activities 1,090 3,854 4,643
Cash flows - financing activities:
Repayments/repurchases of debt (747) (2,903) (4,543)
Debt tender offer and other debt financing fees (17) (123) (179)
Stock repurchases - (656) (763)
Dividends paid to stockholders (266) (243) -
Other, net - - 12
Cash used in financing activities (1,030) (3,925) (5,473)
Net change in cash, cash equivalents and restricted cash (26) (129) (955)
Cash, cash equivalents and restricted cash - beginning balance 99 228 1,183
Cash, cash equivalents and restricted cash - ending balance $ 73 $ 99 $ 228
See Notes to the Condensed Financial Statements.
VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(Millions of Dollars)
December 31,
2020 2019
ASSETS
Cash and cash equivalents $ 73 $ 56
Restricted cash - 43
Trade accounts receivable - net 7 5
Prepaid expense and other current assets 5 100
Total current assets 85 204
Investment in affiliated companies 8,005 8,364
Property, plant and equipment - net 3 4
Identifiable intangible assets - net 47 49
Accumulated deferred income taxes 783 729
Other noncurrent assets 2 67
Total assets $ 8,925 $ 9,417
LIABILITIES AND EQUITY
Long-term debt due currently $ - $ 87
Trade accounts payable 2 1
Accounts payable -affiliates 74 145
Accrued taxes 14 1
Accrued interest - 11
Other current liabilities 4 46
Total current liabilities 94 291
Long-term debt, less amounts due currently - 689
Tax Receivable Agreement obligations 447 455
Other noncurrent liabilities and deferred debits 23 22
Total liabilities 564 1,457
Total stockholders' equity 8,361 7,960
Total liabilities and equity $ 8,925 $ 9,417
See Notes to the Condensed Financial Statements.
NOTES TO CONDENSED FINANCIAL STATEMENTS
1.BASIS OF PRESENTATION
The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of operations and cash flows of Vistra Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the financial statements and related notes of Vistra Corp. and Subsidiaries included in the annual report on Form 10-K for the year ended December 31, 2020. Vistra Corp.'s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.
Vistra Corp. (Parent) files a consolidated U.S. federal income tax return. Consolidated tax expenses or benefits and deferred tax assets or liabilities have been allocated to the respective subsidiaries in accordance with the accounting rules that apply to separate financial statements of subsidiaries.
2.RESTRICTIONS ON SUBSIDIARIES
The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2020, Vistra Operations can distribute approximately $6.7 billion to Vistra Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Vistra Corp. (Parent) of approximately $1.1 billion, $3.9 billion and $4.7 billion during the years ended December 31, 2020, 2019 and 2018, respectively. Additionally, Vistra Operations may make distributions to Vistra Corp. (Parent) in amounts sufficient for Vistra Corp. (Parent) to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Vistra Corp. (Parent)'s ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2020, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Vistra Corp. (Parent) totaled approximately $1.2 billion.
3.GUARANTEES
Vistra Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2020, there are no material outstanding claims related to guarantee obligations of Vistra Corp. (Parent), and Vistra Corp. (Parent) does not anticipate it will be required to make any material payments under these guarantees in the near term.
4.DIVIDEND RESTRICTIONS
Under applicable law, Vistra Corp. (Parent) is prohibited from paying any dividend to the extent that immediately following payment of such dividend there would be no statutory surplus or Vistra Corp. (Parent) would be insolvent.
Vistra Corp. (Parent) received $1.105 billion, $3.890 billion and $4.668 billion in dividends from its consolidated subsidiaries in the years ended December 31, 2020, 2019 and 2018, respectively.
(c) EXHIBITS:
Vistra Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2020
Exhibits Previously Filed With File Number* As
Exhibit
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1 333-215288
Form S-1
(filed December 23, 2016)
2.1 - Order of the United States Bankruptcy Court for the District of Delaware Confirming the Third Amended Joint Plan of Reorganization
2.2 001-38086
Form 8-K
(filed October 31, 2017)
2.1 - Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra Energy Corp. (now known as Vistra Corp.) and Dynegy, Inc.
(3(i)) Articles of Incorporation
3.1 001-38086
Form 8-K
(filed May 4, 2020)
3.1 Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.)
3.2 001-38086
Form 8-K
(filed June 29, 2020)
3.1 - Certificate of Amendment of the Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.), effective July 2, 2020
(3(ii)) By-laws
3.3 ** - Restated Bylaws of Vistra Corp., effective February 23, 2020
Exhibits Previously Filed With File Number* As
Exhibit
(4) Instruments Defining the Rights of Security Holders, Including Indentures
4.1 001-38086
Form 8-K
(filed on August 23, 2018) 4.1 - Indenture for 5.500% Senior Note due 2026, dated as of August 22, 2018, among Vistra Operations Company LLC, as issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
4.2 001-38086
Form 8-K
(filed on August 23, 2018) 4.2 - Form of Rule 144A Global Security for 5.500% Senior Note due 2026 (included in Exhibit 4.1)
4.3 001-38086
Form 8-K
(filed on August 23, 2018) 4.3 - Form of Regulation S Global Security for 5.500% Senior Note due 2026 (included in Exhibit 4.1)
4.4 001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 4.5 - First Supplemental Indenture for the 5.500% Senior Notes due 2026, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.5 001-38086
Form 10-K (filed
on February 28, 2020) 4.36 - Second Supplemental Indenture for the 5.500% Senior Notes due 2026, dated October 25, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.6 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.5 - Third Supplemental Indenture for the 5.500% Senior Notes due 2026, dated January 31, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.7 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.6 - Fourth Supplemental Indenture for the 5.500% Senior Notes due 2026, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.8 ** - Fifth Supplemental Indenture for the 5.500% Senior Notes due 2026, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.9 ** - Sixth Supplemental Indenture for the 5.500% Senior Notes due 2026, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.10 001-38086
Form 8-K
(filed on February 6, 2019) 4.1 - Indenture for 5.625% Senior Note due 2027, dated as of February 6, 2019, among Vistra Operations Company LLC, as issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
4.11 001-38086
Form 8-K
(filed on February 6, 2019) 4.2 - Form of Rule 144A Global Security for 5.625% Senior Note due 2027 (included in Exhibit 4.1)
4.12 001-38086
Form 8-K
(filed on February 6, 2019) 4.3 - Form of Regulation S Global Security for 5.625% Senior Note due 2027 (included in Exhibit 4.1)
4.13 001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 4.6 - First Supplemental Indenture for the 5.625% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.14 001-38086
Form 10-K (filed
on February 28, 2020) 4.41 - Second Supplemental Indenture for the 5.625% Senior Notes due 2027, dated October 25, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
Exhibits Previously Filed With File Number* As
Exhibit
4.15 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.7 - Third Supplemental Indenture for the 5.625% Senior Notes due 2027, dated January 31, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.16 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.8 - Fourth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.17 ** - Fifth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.18 ** Sixth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.19 001-38086
Form 8-K
(filed on June 24, 2019) 4.1 - Indenture for 5.00% Senior Notes due 2027, dated as of June 21, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
4.20 001-38086
Form 8-K
(filed on June 24, 2019) 4.2 - Form of Rule 144A Global Security for 5.00% Senior Notes due 2027 (included in Exhibit 4.1)
4.21 001-38086
Form 8-K
(filed on June 24, 2019) 4.3 - Form of Regulation S Global Security for 5.00% Senior Notes due 2027 (included in Exhibit 4.1)
4.22 001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 4.7 - First Supplemental Indenture for the 5.000% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.23 001-38086
Form 10-K (filed
on February 28, 2020) 4.46 - Second Supplemental Indenture for the 5.000% Senior Notes due 2027, dated October 25, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.24 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.9 - Third Supplemental Indenture for the 5.000% Senior Notes due 2027, dated January 31, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.25 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.10 - Fourth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.26 ** - Fifth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.27 ** - Sixth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.28 001-38086
Form 8-K
(filed on June 17, 2019) 4.1 - Indenture, dated as of June 11, 2019, between Vistra Operations Company LLC, as Issuer, and Wilmington Trust, National Association, as Trustee
4.29 001-38086
Form 8-K
(filed on June 17, 2019) 4.2 - Supplemental Indenture for 3.55% Senior Secured Notes due 2024 and 4.30% Senior Secured Notes Due 2029, dated as of June 11, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
Exhibits Previously Filed With File Number* As
Exhibit
4.30 001-38086
Form 8-K
(filed on June 17, 2019) 4.3 - Form of Rule 144A Global Security for 3.55% Senior Notes due 2024 (included in Exhibit 4.2)
4.31 001-38086
Form 8-K
(filed on June 17, 2019) 4.4 - Form of Rule 144A Global Security for 4.30% Senior Notes due 2029 (included in Exhibit 4.2)
4.32 001-38086
Form 8-K
(filed on June 17, 2019) 4.5 - Form of Regulation S Global Security for 3.55% Senior Notes due 2024 (included in Exhibit 4.2)
4.33 001-38086
Form 8-K
(filed on June 17, 2019) 4.6 - Form of Regulation S Global Security for 4.30% Senior Notes due 2029 (included in Exhibit 4.2)
4.34 001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 4.8 - Second Supplemental Indenture for 3.55% Senior Secured Notes due 2024 and 4.30% Senior Secured Notes due 2029, dated as of August 30, 2019, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.35 001-38086
Form 8-K (filed
on November 21, 2019) 4.1 - Third Supplemental Indenture for 3.55% Senior Secured Notes due 2024 and 4.30% Senior Secured Notes due 2029, dated as of October 25, 2019, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, Subsidiary Guarantors and the Trustee
4.36 001-38086
Form 8-K (filed
on November 21, 2019) 4.2 - Fourth Supplemental Indenture, dated as of November 15, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
4.37 001-38086
Form 8-K (filed
on November 21, 2019) 4.3 - Form of Rule 144A Global Security for 3.70% Senior Note due 2027 (included in Exhibit 4.2)
4.38 001-38086
Form 8-K (filed
on November 21, 2019) 4.4 - Form of Regulation S Global Security for 3.70% Senior Note due 2027 (included in Exhibit 4.2)
4.39 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.11 - Fifth Supplemental Indenture for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of January 31, 2020, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.40 001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 4.12 - Sixth Supplemental Indenture for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of March 26, 2020, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.41 ** - Seventh Supplemental Indenture for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of October 7, 2020, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.42 ** - Eighth Supplemental Indenture for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of January 8, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.43 001-38086
Form 8-K
(filed on August 23, 2018) 4.7 - Purchase and Sale Agreement dated as of August 21, 2018, between TXU Energy Retail Company LLC as originator, and TXU Energy Receivables Company LLC, as purchaser
Exhibits Previously Filed With File Number* As
Exhibit
4.44 001-38086
Form 8-K
(filed on August 23, 2018) 4.8 - Receivable Purchase Agreement dated as of August 21, 2018, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.45 001-38086
Form 8-K
(filed on April 5, 2019) 4.1 - First Amendment to Purchase and Sale Agreement, dated as of April 1, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser
4.46 001-38086
Form 10-Q (Quarter ended June 30, 2019) (filed on August 2, 2019) 4.12 - Second Amendment to Purchase and Sale Agreement, dated as of June 3, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser
4.47 001-38086
Form 8-K
(filed on July 19, 2019) 4.1 - Third Amendment to Purchase and Sale Agreement, dated as of July 15, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser
4.48 001-38086
Form 8-K
(filed on October 16, 2020) 4.1 - Fourth Amendment to Purchase and Sale Agreement, dated as of October 9, 2020, among TXU Energy Retail Company LLC, as an originator and servicer, the other originators named therein, and TXU Energy Receivables Company LLC, as purchaser
4.49 001-38086
Form 8-K
(filed on December 28, 2020) 4.1 - Fifth Amendment to Purchase and Sale Agreement, dated as of December 21, 2020, among TXU Energy Retail Company LLC, certain originators named therein, and TXU Energy Receivables Company LLC, as purchaser
4.50 001-38086
Form 8-K
(filed on April 5, 2019) 4.2 - First Amendment to Receivables Purchase Agreement, dated as of April 1, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.51 001-38086
Form 10-Q (Quarter ended June 30, 2019) (filed on August 2, 2019) 4.13 - Second Amendment to Receivables Purchase Agreement, dated as of June 3, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.52 001-38086
Form 8-K
(filed on July 19, 2019) 4.2 - Third Amendment to Receivables Purchase Agreement, dated as of July 15, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.53 001-38086
Form 8-K
(filed on July 16, 2020) 4.1 - Fifth Amendment to Receivables Purchase Agreement, dated as of July 13, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
Exhibits Previously Filed With File Number* As
Exhibit
4.54 001-38086
Form 8-K
(filed on October 16, 2020) 4.2 - Sixth Amendment to Receivables Purchase Agreement, dated as of October 9, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.55 001-38086
Form 8-K
(filed on December 28, 2020) 4.2 - Seventh Amendment to Receivables Purchase Agreement, dated as of December 21, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.56 ** - Eighth Amendment to Receivables Purchase Agreement, dated as of February 19, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.57 001-33443
Form of 8-K
(filed on February 7, 2017) 4.1 - Warrant Agreement, dated February 2, 2017, by and among Dynegy, Computershare Inc. and Computershare Trust Company, N.A., as warrant agent
4.58 001-38086
Registration Statement on Form 8-A
(filed on April 9, 2018) 4.2 - Supplemental Warrant Agreement, dated as of April 9, 2018 among the Company and the Warrant Agent
4.59 001-33443
Form of 8-K
(filed on February 7, 2017) 4.1 - Form of Warrant
4.60 333-215288
Form S-1
(filed December 23, 2016)
4.1 - Registration Rights Agreement, by and among TCEH Corp. (now known as Vistra Corp.) and the Holders party thereto, dated as of October 3, 2016
4.61 ** - Description of Capital Stock
(10) Material Contracts
Management Contracts; Compensatory Plans, Contracts and Arrangements
10.1 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.6 - 2016 Omnibus Incentive Plan
10.2 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.7 - Form of Option Award Agreement (Management) for 2016 Omnibus Incentive Plan (pre-2021 awards)
10.3 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.8 - Form of Restricted Stock Unit Award Agreement (Management) for 2016 Omnibus Incentive Plan (pre-2021 awards)
10.4 001-33443
Form10-K (Year ended December 31, 2017) (filed on February 26, 2018) 10(d) - Form of Performance Stock Unit Award Agreement for 2016 Omnibus Incentive Plan (pre-2021 awards)
10.5 ** - Form of Option Award Agreement (Management) for 2016 Omnibus Incentive Plan
Exhibits Previously Filed With File Number* As
Exhibit
10.6 ** - Form of Restricted Stock Unit Award Agreement (Management) for 2016 Omnibus Incentive Plan
10.7 ** - Form of Restricted Stock Unit Award Agreement (Director) for 2016 Omnibus Incentive Plan
10.8 ** - Form of Performance Stock Unit Award Agreement for 2016 Omnibus Incentive Plan
10.9 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.9 - Vistra Corp. Executive Annual Incentive Plan
10.10 001-33443
Form10-K (Year ended December 31, 2018) (filed on February 28, 2019) 10.6 - Amended and Restated 2016 Omnibus Incentive Plan, effective as of February 26, 2019
10.11 001-38086
Form 8-K
(filed on May 23, 2019) 10.1 - Amended and Restated 2016 Omnibus Incentive Plan, effective as of May 20, 2019
10.12 001-33443
Form10-K (Year ended December 31, 2018) (filed on February 28, 2019) 10.7 - Vistra Equity Deferred Compensation Plan for Certain Directors, effective as of January 1, 2019
10.13 ** - Amendment No. 1 to the Vistra Equity Deferred Compensation Plan, dated effective as of February 24, 2021
10.14 001-38086
Form 8-K
(filed May 4, 2018)
10.1 - Amended and Restated Employment Agreement, dated as of May 1, 2018, between Curtis A. Morgan and Vistra Energy Corp. (now known as Vistra Corp.)
10.15 001-33443
Form 10-Q (Quarter ended March 31, 2019) (filed on May 3, 2019) 10.5 - Amended and Restated Employment Agreement, dated May 1, 2019, between James A. Burke and Vistra Energy Corp. (now known as Vistra Corp.)
10.16 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.22 - Employment Agreement between Stephanie Zapata Moore and Vistra Energy Corp. (now known as Vistra Corp.)
10.17 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.23 - Employment Agreement between Carrie Lee Kirby and Vistra Energy Corp. (now known as Vistra Corp.)
10.18 001-38086
Form 8-K
(filed February 27, 2020)
10.2 - Employment Agreement between Scott A. Hudson, Vistra Energy Corp. (now known as Vistra Corp.) and TXU Retail Service Company
10.19 001-38086
Form 8-K
(filed February 27, 2020)
10.1 - Employment Agreement between Stephen J. Muscato, Vistra Energy Corp. (now known as Vistra Corp.) and Luminant Energy Company LLC
10.20 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.26 - Form of indemnification agreement with directors
Exhibits Previously Filed With File Number* As
Exhibit
10.21 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.29 - Stock Purchase Agreement, dated as of October 25, 2016, by and between TCEH Corp. (now known as Vistra Corp.) and Curtis A. Morgan
Credit Agreements and Related Agreements
10.22 333-215288
Form S-1
(filed December 23, 2016)
10.1 - Credit Agreement, dated as of October 3, 2017
10.23 333-215288
Form S-1
(filed December 23, 2016)
10.2 - Amendment to Credit Agreement, dated December 14, 2016, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.24 333-215288
Amendment No. 1
to Form S-1
(filed February 14, 2017)
10.3 - Second Amendment to Credit Agreement, dated February 1, 2017, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.25 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.4 - Third Amendment to Credit Agreement, dated February 28, 2017, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.26 001-38086
Form 8-K
(filed August 17, 2017)
10.1 - Fourth Amendment to Credit Agreement, dated as of August 17, 2017 (effective August 17, 2017), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.27 001-38086
Form 8-K
(filed December 14, 2017)
10.1 - Fifth Amendment to Credit Agreement, dated as of December 14, 2017 (effective December 14, 2017), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.28 001-38086
Form 8-K
(filed February 22, 2018)
10.1 - Sixth Amendment to Credit Agreement, dated as of February 20, 2018 (effective February 20, 2018), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.29 001-38086
Form 8-K
(filed June 15, 2018)
10.1 - Seventh Amendment to Credit Agreement, dated as of June 14, 2018, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties party thereto, Credit Suisse and Citibank, N.A. as the 2018 Incremental Term Loan Lenders, the various other Lenders party thereto, Credit Suisse as Successor Administrative Agent and as Successor Collateral Agent, and Delaware Trust Company, as Collateral Trustee.
10.30 001-38086
Form 8-K
(filed April 4, 2019)
10.4 - Eighth Amendment to Credit Agreement, dated March 29, 2019, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties (as defined in the Vistra Operations Credit Agreement) party thereto, Bank of Montreal, Chicago Branch, as new Revolving Loan Lender, Revolving Letter of Credit Issuer and Joint Lead Arranger, the various other Lenders and Letter of Credit Issuers party thereto, and Credit Suisse as Administrative Agent and Collateral Agent
Exhibits Previously Filed With File Number* As
Exhibit
10.31 001-38086
Form 8-K
(filed May 29, 2019)
10.1 - Ninth Amendment to Credit Agreement, dated May 29, 2019, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties (as defined in the Vistra Operations Credit Agreement) party thereto, Sun Trust Bank, as incremental Revolving Loan Lender, and Credit Suisse AG, Cayman Island Branch, as Administrative Agent and Collateral Agent
10.32 001-38086
Form 8-K (filed
on November 21, 2019) 10.1 - Tenth Amendment to the Credit Agreement, dated November 15, 2019, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, the other Credit Parties (as defined in the Credit Agreement) party thereto, Credit Suisse AG, Cayman Islands Branch (as the 2019 Incremental Term Loan Lender and as Administrative Agent and as Collateral Agent), and the other Lenders party thereto
10.33 001-38086
Form 8-K
(filed on August 7, 2018) 10.1 - Purchase Agreement, dated August 7, 2018, by and among Vistra Operations Company LLC and Citigroup Global Markets Inc., on behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement
10.34 001-38086
Form 8-K
(filed on January 24, 2019) 10.1 - Purchase Agreement, dated January 22, 2019, by and among Vistra Operations Company LLC and J.P. Morgan Securities LLC. On behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement
10.35 001-38086
Form 8-K
(filed on June 7, 2019) 10.1 - Purchase Agreement, dated June 4, 2019, by and among Vistra Operations Company LLC and Citigroup Global Markets Inc., on behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement
10.36 001-38086
Form 8-K
(filed on June 7, 2019) 10.2 - Purchase Agreement, dated June 6, 2019, by and among Vistra Operations Company LLC and Goldman Sachs & Co. LLC, on and behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement
10.37 001-38086
Form 8-K (filed
on November 13, 2019) 10.1 - Purchase Agreement, dated November 6, 2019, by and among Vistra Operations Company LLC and J.P. Morgan Securities LLC, on behalf of itself and the several Initial Purchases named in Schedule I to the Purchase Agreement
10.38 001-38086
Form 8-K
(filed on April 9, 2018)
10.10 - Assumption Agreement, dated as of April 9, 2018, between Vistra Energy Corp. (now known as Vistra Corp.) (as successor by merger to Dynegy Inc.), and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and as Collateral Trustee.
10.39 001-38086
Form 8-K
(filed on April 9, 2018)
10.11 - Guarantee and Collateral Agreement, dated as of April 23, 2013, among Dynegy Inc., the subsidiaries of the borrower from time to time party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013).
10.40 001-38086
Form 8-K
(filed on April 9, 2018)
10.12 - Joinder, dated as of April 9, 2018, among Vistra Energy Corp. (now known as Vistra Corp.), the subsidiary guarantors party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee.
10.41 001-38086
Form 8-K
(filed on April 9, 2018)
10.13 - Collateral Trust and Intercreditor Agreement, dated as of April 23, 2013 among Dynegy, the Subsidiary Guarantors (as defined therein), Credit Suisse AG, Cayman Islands Branch and each person party thereto from time to time (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013).
Exhibits Previously Filed With File Number* As
Exhibit
Other Material Contracts
10.42 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.5 - Collateral Trust Agreement, dated as of October 3, 2016, by and among TEX Operations Company LLC (now known as Vistra Operations LLC), the Grantors from time to time thereto, Railroad Commission of Texas, as first-out representative, and Deutsche Bank AG, New York Branch, as senior credit agreement representative
10.43 001-38086
Form 8-K
(filed on June 15, 2018) 10.2 - Amendment to Collateral Trust Agreement, effective as of June 14, 2018, among Vistra Operations Company LLC, the other Grantors from time to time party thereto, Railroad Commission of Texas, as first-out representative, and Credit Suisse AG, Cayman Islands Branch, as senior credit agreement agent, and Delaware Trust Company, as Collateral Trustee
10.44 001-38086
Form 8-K
(filed on June 15, 2018) 10.3 - Collateral Trust Joinder, dated June 14, 2018, between the Additional Grantors party thereto and Delaware Trust Company, as Collateral Trustee, to the Collateral Trust Agreement, effective pursuant to the Seventh Amendment as of June 14, 2018, among Vistra Operations Company LLC, the other Grantors from time to time party thereto, Railroad Commission of Texas, as First-Out Representative, Credit Suisse AG, Cayman Islands Branch, as Senior Credit Agreement Agent, and Delaware Trust Company, as Collateral Trustee.
10.45 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.13 - Tax Receivable Agreement, by and between TEX Energy LLC (now known as Vistra Corp.) and American Stock Transfer & Trust Company, as transfer agent, dated as of October 3, 2016
10.46 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.14 - Tax Matters Agreement, by and among TEX Energy LLC (now known as Vistra Corp.), EFH Corp., Energy Future Intermediate Holding Company LLC, EFI Finance Inc. and EFH Merger Co. LLC, dated as of October 3, 2016
10.47 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.15 - Transition Services Agreement, by and between Energy Future Holdings Corp. and TEX Operations Company LLC (now known as Vistra Operations Company LLC), dated as of October 3, 2016
10.48 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.16 - Separation Agreement, by and between Energy Future Holdings Corp., TEX Energy LLC (now known as Vistra Corp.) and TEX Operations Company LLC (now known as Vistra Operations LLC), dated as of October 3, 2016
10.49 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.17 - Purchase and Sale Agreement, dated as of November 25, 2015, by and between La Frontera Ventures, LLC and Luminant Holding Company LLC
10.50 333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.18 - Amended and Restated Split Participant Agreement, by and between Oncor Electric Delivery Company LLC (f/k/a TXU Electric Delivery Company) and TEX Operations Company LLC (now known as Vistra Operations Company LLC), dated as of October 3, 2016
10.51 001-38086
Form 8-K
(filed July 7, 2017)
10(a) - Asset Purchase Agreement, dated as of July 5, 2017, by and among Odessa-Ector Power Partners, L.P., La Frontera Holdings, LLC, Vistra Operations Company LLC, Koch Resources, LLC
10.52 001-38086
Form 8-K
(filed on October 16, 2020) 10.1 - Master Framework Agreement, dated as of October 9, 2020, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, and MUFG Bank, Ltd., as buyer
Exhibits Previously Filed With File Number* As
Exhibit
10.53 001-38086
Form 8-K
(filed on October 16, 2020) 10.2 - Master Repurchase Agreement, dated as of October 9, 2020, between TXU Energy Retail Company LLC and MUFG Bank, Ltd.
10.54 001-38086
Form 8-K
(filed on December 28, 2020) 10.1 - Joinder Agreement, dated as of December 21, 2020, among TXU Energy Retail company LLC, as seller party agent, Vistra Operations Company LLC, as guarantor, certain originators named therein, and MUFG Bank, Ltd., as buyer
(21) Subsidiaries of the Registrant
21.1 ** - Significant Subsidiaries of Vistra Corp.
(23) Consent of Experts
23.1 ** - Consent of Deloitte & Touche LLP
(31) Rule 13a-14(a) / 15d-14(a) Certifications
31.1 ** - Certification of Curtis A. Morgan, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 ** - Certification of James A. Burke, principal financial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32) Section 1350 Certifications
32.1 *** - Certification of Curtis A. Morgan, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 *** - Certification of James A. Burke, principal financial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95) Mine Safety Disclosures
95.1 ** - Mine Safety Disclosures
XBRL Data Files
101.INS ** - The following financial information from Vistra Corp.'s Annual Report on Form 10-K for the year ended December 31, 2020 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statement of Changes in Equity (vi) the Notes to the Consolidated Financial Statements.
101.SCH ** - XBRL Taxonomy Extension Schema Document
101.CAL ** - XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF ** - XBRL Taxonomy Extension Definition Linkbase Document
101.LAB ** - XBRL Taxonomy Extension Label Linkbase Document
101.PRE ** - XBRL Taxonomy Extension Presentation Linkbase Document
104 - The Cover Page Interactive Data File does not appear in Exhibit 104 because its XBRL tags are embedded within the inline XBRL document.
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* Incorporated herein by reference
** Filed herewith
*** Furnished herewith