Item 1. BUSINESS

References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.

Business

Vistra Energy is a holding company operating an integrated retail and 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 General Corporate Law in 2016.

We serve approximately 4.6 million customers and operate in 20 states and the District of Columbia. Our generation fleet totals approximately 38,500 MW of generation capacity with a portfolio of natural gas, nuclear, coal, solar and battery energy storage facilities.

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), (v) MISO and (vi) Asset Closure. See Note 20 to the Financial Statements for further information concerning reportable business segments.

As of December 31, 2019, we had approximately 5,475 full-time employees, including approximately 1,690 employees under collective bargaining agreements.

Acquisitions and Merger

Ambit Transaction — On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the acquisition of Ambit (Ambit Transaction). Because the Ambit Transaction closed on November 1, 2019, Vistra Energy'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 Energy 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 Energy'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 Energy and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. Because the Merger closed on April 9, 2018, Vistra Energy'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.

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• Disciplined capital allocation. Vistra Energy 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 Energy's interest expense is manageable in a variety of wholesale power price environments while giving Vistra Energy 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 Energy'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 TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and US 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 value increases as a function 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 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 flow 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.

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• Growth and enhancement. 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 these 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 will need to have compelling economic value in addition to fitting with our business strategy.

• 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 2020, the Board declared a quarterly dividend of $0.135 per share that will be paid in March 2020.

Market Discussion

The operations of Vistra Energy are aligned into six reportable business segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE, (v) MISO and (vi) Asset Closure. The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers. The ERCOT, PJM, NY/NE (comprising NYISO and ISO-NE) and MISO segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely within their respective RTO or ISO market. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. Our CAISO operations are included in the Corporate and Other non-segment as our operations in the CAISO market do not materially affect our financial condition, results of operations and cash flows. See Note 20 to the Financial Statements for additional information related to our operating segments.

Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)

Separately, RTOs and ISOs 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. RTOs and ISOs administer energy and ancillary service markets in the short term, usually day-ahead and real-time markets. Several RTOs and ISOs also ensure long-term planning reserves through monthly, semiannual, annual and multiyear capacity markets. The RTOs and ISOs 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 RTOs/ISOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and responsibilities do not generally overlap.

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In RTO and ISO regions with centrally dispatched market structures, 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 RTO/ISO may produce different prices respective to other zones within the same RTO/ISO 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. In RTO and ISO regions with centrally dispatched market structures and location-based marginal price clearing structures (e.g. PJM, ISO-NE, NYISO, ERCOT, MISO, and CAISO), generators will receive the location-based marginal price for their output. The location-based marginal price, absent congestion, would be the marginal price of the most expensive unit needed to meet demand. In regions that are outside the footprint of RTOs/ISOs, prices are determined on a bilateral basis between buyers and sellers.

Retail Markets

The Retail segment is engaged in retail sales of electricity, natural gas and related services to approximately 4.6 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 US 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 2.3 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, having one of the lowest customer complaint rates according to the PUCT. As of December 31, 2019, we provided electricity to approximately 31% of the residential customers in ERCOT and for more than 10% 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, US Gas & Electric and Ambit Energy retail businesses, through which we provide retail electricity, natural gas and related services to approximately 2.3 million customers in 18 states and the District of Columbia.

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ERCOT Market

ERCOT is an ISO that manages the flow of electricity from approximately 82,000 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. 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. In 2019, ERCOT implemented a .25 standard deviation shift 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. Subsequently, in 2020 ERCOT will implement an additional .25 standard deviation shift in the loss of load probability calculation, which is expected to result in a steeper price escalation during scarcity events in 2020 relative to 2019. Because ERCOT has limited excess generation capacity to meet high demand days due to its minimal import capacity, and peaking facilities have high operating costs, the marginal price of supply rapidly increases during periods of high demand. Historically, elevated temperatures in the summer months have driven high electricity demand in ERCOT. Many generators benefit from these sporadic periods of "scarcity pricing" in which power prices may increase significantly, up to the current $9,000/MWh price cap. 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, forward 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 spot market in which electricity may be sold 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-up, regulation service-down, responsive reserve service and non-spinning reserve service. Regulation service up and down are used to balance the grid in a near-instantaneous fashion when supply and demand fluctuate due to a variety of factors, such as weather, generation outages, renewable production intermittency and transmission outages. Responsive reserves and non-spinning reserves are used by ERCOT when the grid is at, near or recovering from a state of emergency due to inadequate generation. Because ERCOT has one of the highest concentrations of wind capacity generation among U.S. markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind production, making ERCOT more vulnerable to periods of generation scarcity.

Our ERCOT segment is comprised of 20 power generation facilities located in Texas totaling 18,356 MW of generation capacity. Our ERCOT fleet includes seven CCGT natural gas-fueled generation facilities totaling 7,838 MW, three lignite/coal-fueled generation facilities totaling 4,500 MW, eight natural gas-fueled peaking generation facilities totaling 3,538 MW, a nuclear generation facility totaling 2,300 MW and a solar photovoltaic power generation facility totaling 180 MW. We also operate a 10 MW battery energy storage system (ESS) at our Upton 2 solar facility.

PJM Market

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.

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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. This market is transparent, allowing generators and load serving entities to see real-time price effects, transmission constraints and the impacts of congestion at each pricing point. 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 long-term markets 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. We also enter into bilateral capacity transactions. PJM's Capacity Performance (CP) rules are designed to improve system reliability and include penalties for under-performing units and reward for over-performing units during shortage events. PJM's base capacity resources are those capacity resources not capable of sustained, predictable operation throughout the entire delivery year, but can provide energy and reserves during hot weather operations. The base capacity resources are subject to non-performance charges assessed during emergency conditions from June through September. Full transition of the capacity market to CP rules will occur by 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.

Our PJM segment is comprised of 17 power generation facilities totaling 10,769 MW of generating capacity. Our PJM fleet includes eight CCGT natural gas-fueled generation facilities totaling 5,902 MW, three coal-fueled generation facilities totaling 3,428 MW, four natural gas-fueled generation facilities totaling 1,346 MW and two oil-fueled generation facilities totaling 93 MW. Of these facilities, eight are located in Ohio, three in Pennsylvania, three in Illinois and one each in New Jersey, Virginia and West Virginia.

NYISO and ISO-NE Markets

NYISO is an ISO that manages the flow of electricity from approximately 39,000 MW of installed generation capacity to approximately 20 million New York customers.

The NYISO market dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. 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.

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. 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.

Our NY/NE segment is comprised of eight CCGT natural gas-fueled generation facilities totaling 4,730 MW of generation capacity. Of these facilities, four are located in Massachusetts, two in Connecticut and one each in Maine and New York.

MISO Market

MISO is an RTO that manages the flow of electricity from approximately 190,000 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.

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The MISO energy market is designed to ensure that all market participants have open-access to the transmission system on a non-discriminatory basis. MISO, as an independent RTO, maintains functional control over the use of the transmission system to ensure transmission circuits do not exceed their secure operating limits and become overloaded. MISO operates day-ahead and real-time energy markets using a similar LMP methodology as described above for the PJM market. 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 Forward Capacity 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.

Our MISO segment is comprised of four power generation facilities located in Illinois totaling 3,408 MW of generation capacity. Joppa, which is within the Electric Energy, Inc. (EEI) control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO. Edwards is scheduled to be retired by the end of 2022 pursuant to the terms of a federal consent decree. We currently offer a portion of our MISO segment generating capacity and energy into PJM. Our Edwards and Newton generation facilities have 1,200 MW electrically tied into PJM through pseudo-tie arrangements. These pseudo-tie arrangements are scheduled to terminate on March 1, 2020, after which time Edwards and Newton will offer their generating capacity and energy solely into MISO.

CAISO Market

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 utilizing an LMP methodology as described above. The capacity market is comprised of Generic, Flexible and Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission. Unlike other centrally cleared capacity markets, the resource adequacy market in California is a bilaterally traded market. In November 2016, CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market. The voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a modification to the Capacity Procurement Mechanism (CPM) and provides another avenue to sell RA capacity.

Our CAISO operations are comprised of two power generation facilities located in California totaling 1,185 MW of generating capacity. Our CAISO fleet includes one CCGT natural gas-fueled generation facility totaling 1,020 MW and one oil-fueled generation facility totaling 165 MW. In 2018 and 2019, we announced the planned development of a 300 MW ESS at our Moss Landing facility and a 20 MW ESS at our Oakland facility (see Note 3 to the Financial Statements).

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 RTO/ISO 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.

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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 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 may make such fluctuations more pronounced. However, not all regions of the U.S. typically experience extreme weather conditions at the same time, so Vistra Energy is typically not exposed to the effects of extreme weather in all parts of its business at once. 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 competitive energy 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 18 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 US Gas & Electric through the Ambit Transaction, Crius Transaction and the Merger. As of December 31, 2019, we have reflected intangible assets on our balance sheet for our trade names of approximately $1.391 billion (see Note 6 to the Financial Statements).

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.

Climate Change

There is attention and interest nationally 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 116 million short tons of CO2 in 2019.

We have already taken or announced significant steps to transition the fuel-mix and reduce the emissions profile of our generation fleet, including:

• 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 in connection with the Merger.

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• Retirement 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 585 MW of coal-fueled generation facilities in Illinois by the end of 2022.

• Solar Development Project — In 2018, we began commercial operation of our 180 MW Upton 2 solar facility.

• Battery Energy Storage Projects — In 2018, a 10 MW battery energy storage system (ESS) at our Upton 2 solar facility became operational. In 2018 and 2019, we announced the planned development of a 300 MW ESS at our Moss Landing facility and a 20 MW ESS at our Oakland facility. In 2019, we began construction of the Moss Landing ESS.

See Note 4 to the Financial Statements for discussion of our retirement of generation facilities and Note 3 for discussion of our solar and battery energy storage projects.

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. States must submit their plans for regulating GHG emissions from existing facilities by July 2022. 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. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units. Vistra Energy submitted comments on that proposed rulemaking. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, the rules, if implemented, could have a material impact on our results of operations, liquidity or financial condition.

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. The RGGI cap on CO2 emissions would decline by 2.275 million tons per year beginning in 2021. Each RGGI state will work to ensure that its program changes are in effect by 2021.

Our generating facilities in Connecticut, Maine, Massachusetts and New York emitted approximately 7.8 million tons of CO2 during 2019. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2019 was approximately $5.65 per allowance. The spot market price of RGGI allowances required to operate our affected facilities during 2020 was $5.94 per allowance on February 24, 2020. 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.

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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 is intended to link Virginia to RGGI.

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.

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of SO2 and NOX emissions from our fossil-fueled generation units. After certain EPA revisions to the rule, the CSAPR became effective January 1, 2015. In October 2016, the EPA issued a CSAPR update, which revised the ozone season NOx limits for 22 eastern states, including Texas. Under the CSAPR, our generating facilities in Illinois, Ohio, New Jersey, New York, Pennsylvania, Virginia, and West Virginia are subject to cap-and-trade programs for ozone-season emissions of NOx from May 1 through September 30 and for annual emissions for SO2 and NOX. Our generating facilities in Texas are subject to the CSAPR NOx ozone season cap-and-trade program. While we cannot predict the outcome of future proceedings related to the CSAPR, based upon our current operating plans, we do not believe that the CSAPR itself will cause any material operational, financial or compliance issues to our business or require us to incur any material compliance costs.

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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 January 2016, the EPA issued a final rule approving in part and disapproving in part Texas's 2009 State Implementation Plan (SIP) as it relates to the reasonable progress component of the Regional Haze Program and issuing a Federal Implementation Plan (FIP). The EPA's emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generation units (including Big Brown Units 1 and 2, Monticello Units 1 and 2 and Coleto Creek) and upgrades to existing scrubbers at seven generation units (including Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4).

In March 2016, various parties (including Luminant and the State of Texas) filed petitions for review in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the FIP's Texas requirements. In July 2016, the Fifth Circuit Court granted motions to stay the rule pending final review of the petitions for review. In March 2017, the Fifth Circuit Court granted a motion by the EPA to remand the rule back to the EPA for reconsideration. The stay of the rule (and the emission control requirements) remains in effect. The retirements of our Monticello, Big Brown and Sandow 4 plants should have a favorable impact on this rulemaking and litigation. Further, we believe that these retirements and the BART rule (discussed below) obviates the need for any additional limits on our remaining Texas plants to address the requirements in the regional haze rule. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

In September 2017, the EPA signed a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas's 2009 SIP and a partial FIP. For SO2, the rule creates 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. We believe the retirements of our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO2. For NOX, the rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves 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 until the EPA concludes the reconsideration process. In August 2018, the EPA issued a proposal to affirm the prior BART final rule and seeking comments on that proposal, which were due in October 2018. In November 2019, the EPA proposed additional revisions to the BART final rule, and we submitted comments on that proposal in January 2020. While we cannot predict the outcome of the rulemaking and legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operations, liquidity or financial condition.

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 January 2020, the EPA took final action to withdraw the Texas SIP Call. While we cannot predict the timing or outcome of the rulemaking and legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operations, liquidity or financial condition.

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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. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

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 January 2020, New York and Connecticut filed a lawsuit against the EPA in the Southern District of New York to compel the EPA to comply with the court's June 2018 order.

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. While we cannot predict the outcome of the judicial proceedings, given that the Zimmer facility utilizes SCR technology to control NOX emissions, we do not believe that the result of these proceedings 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. Briefing in the D.C. Circuit Court is ongoing.

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Illinois Multi-Pollutant Standards (MPS)

In August 2019, changes proposed by the Illinois Pollution Control Board to the Illinois multi-pollutant standard rule (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 the company's generation in MISO. See Note 4 to the Financial Statements for information regarding the retirement of the four plants.

CAA Matters

Zimmer NOVs — In December 2014, the EPA issued a notice of violation (NOV) alleging violation of opacity standards at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan and the station's air permits including standards applicable to opacity, sulfur dioxide, sulfuric acid mist and heat input. In January 2020, the U.S. Department of Justice filed a complaint and proposed consent decree agreed to by Dynegy Zimmer, LLC in the U.S. District Court for the Southern District of Ohio that would resolve claims alleged in the 2008, 2010 and 2014 NOVs. The court has not yet entered the consent decree as effective. We believe that if the consent decree is entered by the court as proposed, it will not have a material impact on our results of operations, liquidity or financial condition.

Edwards CAA Citizen Suit — In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois against one of our subsidiaries that owns the Edwards Power Plant alleging violations of opacity and particulate matter limits at our MISO segment's Edwards facility. In August 2016, the district court granted the plaintiffs' motion for summary judgment on certain liability issues. In September 2019, the parties to the lawsuit announced a proposed settlement which was approved by the court in a consent decree in November 2019. The consent decree requires the retirement of the Edwards plant by the end of 2022 and funding for certain projects that benefit Peoria-area communities. See Note 4 to the Financial Statements for information regarding the expected retirement of the Edwards plant.

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.

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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 extend 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. The EPA is expected to undertake further revisions to its CCR regulations in response to the D.C. Circuit Court's ruling. In October 2018, the rule that extends certain closure deadlines to 2020 was challenged in the D.C. Circuit Court. In March 2019, the D.C. Circuit Court granted the EPA's request for remand without vacatur. In December 2019, the EPA issued a proposed rule that would revise the closure deadlines for unlined CCR impoundments from October 31, 2020 to August 31, 2020 and establish new procedures for seeking extensions of the August 31, 2020 closure deadline. One method to receive an extension of the August 31, 2020 deadline would require notifying the EPA by May 2020 that the affected power generation facility will retire by either 2023 or 2028 depending upon the size of the affected facility’s impoundments. If the rule is finalized as proposed, we may decide to avail ourselves of this retirement extension mechanism for some of our facilities. We filed comments on the proposal in January 2020. While we cannot predict the impacts of these rule revisions (including whether and if so how the states in which we operate will utilize the authority delegated to the states through the revisions), or estimate a range of reasonably possible costs related to these revisions, the changes that result from these revisions could have a material impact on our results of operations, liquidity or financial condition.

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. That appeal is now stayed. 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 early stages. We dispute the allegations in both of these matters and will vigorously defend our position.

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. We dispute the allegations and will vigorously defend our position.

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. We anticipate IEPA's proposed rule will be issued in March 2020 and expect the rulemaking process should be completed by early 2021. Under the new law, 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 law does not mandate closure by removal at any site. While we cannot predict the outcome of this rulemaking process, the final rule could have a material impact on our ARO, results of operations, liquidity or financial condition.

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For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are necessary 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. At this time, in part because of the revisions to the CCR rule that the EPA published in July 2018, the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule and the Illinois coal ash rulemaking, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any, that ultimately may be required. 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.

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 approximately $16 million, depending on the final technology needed for compliance at our Illinois plants. 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 final rule and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration of the 2015 ELG final 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 2015 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.

Given the EPA's decision to reconsider the FGD and bottom ash wastewater provisions of the ELG rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, the uncertainty stemming from the vacatur of the effluent limitations for legacy wastewater and leachate, and the intertwined relationship of the ELG rule with the CCR rule discussed above, which is also being reconsidered by the EPA, as well as pending legal challenges concerning both rules, substantial uncertainty exists regarding our projected capital expenditures for ELG compliance, including the timing of such expenditures. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

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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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