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 in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive electricity market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users.

We serve approximately 2.8 million customers in five states. Our generation fleet totals approximately 40,500 MW of generation capacity with a portfolio of natural gas, nuclear, coal and solar 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. The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets served by businesses acquired in the Merger. See Note 22 to the Financial Statements for further information concerning reportable business segments.

As of December 31, 2018, we had approximately 5,275 full-time employees, including approximately 2,030 employees under collective bargaining agreements.

Merger

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. See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting.

Business Strategy

Our business strategy is to deliver long-term stakeholder value through a focus on the following areas:

Recent Developments

Entry into Purchase Agreement to Acquire Crius Energy Trust — On February 7, 2019, Vistra Energy and Crius Energy Trust (Crius) entered into a definitive agreement, which was subsequently amended on February 19, 2019 (as amended, the Crius Purchase Agreement), as a result of an unsolicited acquisition proposal, pursuant to which Vistra Energy will acquire the equity interest of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). Crius is an energy retailer selling both electricity and natural gas products to residential and small business customers in 19 states and the District of Columbia.

The acquisition provides a high degree of overlap with Vistra Energy's generation fleet and contains approximately 11.6 TWh of annual load, improving Vistra Energy's match of its generation to load profile to approximately 45 percent, reducing risk. The acquisition also establishes a platform for future growth by leveraging Vistra Energy's existing retail marketing capabilities and Crius's experienced team. The acquisition enhances the integrated value proposition through collateral and transaction efficiencies, particularly via Crius's largely retail portfolio.

Vistra Energy intends to fund the purchase price of approximately $378 million using cash on hand and assumption of Crius's net debt of approximately $108 million. Completion of the Crius Transaction is subject to various customary conditions, including, among others, (i) approval by at least two-thirds of the Crius unitholders and (ii) receipt of all requisite regulatory approvals, which include approvals of the FERC and the expiration and termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Pending the receipt of all necessary approvals and the fulfillment of all other customary closing conditions, the parties expect the transaction to close in the second quarter of 2019.

Dividend Declaration — On February 26, 2019, Vistra Energy announced that the Board had declared a dividend pursuant to which Vistra Energy would pay, to each holder of record as of March 15, 2019, a dividend of $0.125 per share, to be paid March 29, 2019.

Issuance of Vistra Operations 5.625% Senior Notes Due 2027 — In February 2019, Vistra Operations issued and sold $1.3 billion aggregate principal amount of 5.625% senior notes due 2027 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act of 1933, as amended. The senior 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 from the sale of the senior notes totaling approximately $1.287 billion , 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 2019 Tender Offer described below, (ii) the redemption of approximately $35 million aggregate principal amount of our 7.375% senior notes due 2022 and (iii) the redemption of the remaining approximately $25 million aggregate principal amount of our outstanding 8.034% senior notes due 2024.

2019 Tender Offer and Consent Solicitation — In February 2019, Vistra Energy used the net proceeds from the issuance of the Vistra Operations 5.625% senior notes due 2027 to fund a cash tender offer (the 2019 Tender Offer) to purchase for cash approximately $1.193 billion aggregate principal amount of 7.375% senior notes due 2022 assumed in the Merger.

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 related services 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 22 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.

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 and related services to approximately 2.8 million customers. Substantially all of these activities are conducted by TXU Energy and Value Based Brands in Texas, Dynegy Energy Services in Massachusetts, Ohio, Illinois and Pennsylvania and Homefield Energy in Illinois.

The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 1.7 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, having one of the lowest customer complaint rates according to the PUCT and having an integrated power generation and wholesale operation that allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost. As of December 31, 2018 , we provided electricity to approximately 23% and 20% of the residential and commercial customers in ERCOT, respectively. 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, such as Free Nights and Solar Days residential plans, MyEnergy Dashboard ^SM , TXU iThermostat product and mobile solution, the TXU Energy Rewards program, the TXU Energy Green UP ^SM renewable energy credit program and a diverse set of solar options, which give our customers choice, convenience and control over how and when they use electricity and related services. We competitively market electricity and related services to acquire, serve and retain retail customers. We believe we are situated to better serve our retail customers through our unique affiliation with our wholesale commodity risk management personnel who can 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), which results in significantly 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 (primarily TXU Energy) 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.

We also serve residential, municipal, commercial and industrial customers through our Homefield Energy and Dynegy Energy Services retail businesses, through which we provide retail electricity to approximately 1.1 million customers in Illinois, Massachusetts, Ohio and Pennsylvania.

ERCOT Market

ERCOT is an ISO that manages the flow of electricity from approximately 78,000 MW of installed capacity to approximately 25 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. 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.

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 18,366 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, a solar photovoltaic power generation facility totaling 180 MW and a battery energy storage system totaling 10 MW.

PJM Market

PJM is an RTO that manages the flow of electricity from approximately 178,000 MW of 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.

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 base residual 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 an 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 and six natural gas- or oil-fueled generation facilities totaling 1,439 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 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 went into effect for planning year 2018-2019 (FCA-9), which will 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 200,000 MW of installed 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.

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 FCA 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 FTR 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 eight power generation facilities located in Illinois totaling 5,476 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. We currently offer a portion of our MISO segment generating capacity and energy into PJM. Our Coffeen, Duck Creek, Edwards and Newton generation facilities have 2,540 MW electrically tied into PJM through pseudo-tie arrangements. Our Hennepin generation facility offers 294 MW of the facility's energy and capacity into PJM as a block schedule and began dispatching as a pseudo-tie unit for planning year 2018-2019.

CAISO Market

CAISO is an ISO that manages the flow of electricity from approximately 60,000 MW of installed capacity to approximately 30 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. There have been recent CPM designations through the Competitive Solicitation Process. These include Moss Landing Unit 1 for 510 MW for the calendar year 2018 and Moss Landing Unit 2 intra-monthly designation for 29 MW for September through November 2018.

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 June 2018, we announced that we will enter into a 20 -year resource adequacy contract with Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power Plant site in California. PG&E filed its application with the California Public Utilities Commission (CPUC) in June 2018 and the CPUC approved the contract in November 2018. We anticipate the battery storage project will enter commercial operations by the fourth quarter of 2020.

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.

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 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 17 years, is registered and protected by trademark law and is the only material intellectual property asset that we own. As of December 31, 2018 , we have reflected an intangible asset on our balance sheet for the TXU Energy brand of approximately $1.2 billion (see Note 8 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 15 to the Financial Statements for a discussion of litigation related to EPA reviews.

Climate Change

There is a debate nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide (CO ₂ ), might 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. CO ₂ , methane and nitrous oxide are emitted in this combustion process, with CO ₂ representing the largest portion of these GHG emissions. We estimate that our generation facilities produced approximately 135 million short tons of CO ₂ in 2018.

Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address GHG emissions from new, modified and reconstructed and existing 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 CO ₂ emissions. Various parties (including Luminant) filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court), and subsequently, in January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the U.S. Supreme Court (Supreme Court) asking that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for existing plants. In February 2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the Supreme Court disposes of any subsequent petition for review. Oral argument on the merits of the legal challenges to the rule was heard in September 2016 before the entire D.C. Circuit Court, but the D.C. Circuit Court has not issued a decision and the case remains in abeyance due to the EPA's decision to review the Clean Power Plan.

In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan with the proposed repeal focusing on what the EPA believes to be the unlawful nature of the Clean Power Plan and asking for public comment on the EPA's interpretations of its authority under the Clean Air Act. In December 2017, the EPA published an advance notice of proposed rulemaking (ANPR) soliciting information from the public as the EPA considers proposing a future rule. Vistra Energy submitted comments on the ANPR in February 2018. Vistra Energy submitted comments on the proposed repeal in April 2018. In August 2018, the EPA published a proposed replacement rule called the Affordable Clean Energy rule. We submitted comments on the proposed Affordable Clean Energy rule in October 2018. In December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units with comments due in March 2019. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately implemented or upheld as they were issued, they 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 CO ₂ 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 CO ₂ budget trading program, including an additional 30 percent reduction in the CO ₂ annual cap by the year 2030, relative to 2020 levels. The RGGI cap on CO ₂ 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 8.3 million tons of CO ₂ during 2018. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2018 was approximately $5.39 per allowance. The spot market price of RGGI allowances required to operate our affected facilities during 2019 was $5.40 per allowance on February 25, 2019. 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 CO ₂ 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 CO ₂ 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 will transition to a competitive auction process. Allowances for 2019 and 2020 will be 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. The New England Power Generators Association, in which we are a member, and other generators filed complaints in Massachusetts superior court challenging the rules. In January 2018, the Massachusetts Supreme Judicial Court decided to review the challenges to MassDEP's electricity generation unit's CO ₂ rules and transferred the case from the superior court where the rule was upheld. Based on current projections of operations for our Massachusetts generating facilities in 2019, we anticipate that allocated allowances will cover CO ₂ emissions. We expect the rules will have little or no near-term impact on the financial results of our generating facilities in Massachusetts. However, if upheld, the rules would have an adverse impact on the long-term future of these facilities.

Virginia — In January 2018, the Virginia Department of Environmental Quality issued a proposed rule to adopt a carbon cap-and trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020. The proposed 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. In December 2018, New Jersey published two rule proposals that would establish the mechanisms for New Jersey to rejoin RGGI.

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. The CARB and the Province of Québec held their seventeenth joint allowance auction in November 2018 with current vintage auction allowances selling at a clearing price of $15.31 per metric ton and 2021 auction allowances selling at a clearing price of $15.33 per metric ton. The CARB expects allowance prices to be in the $15 to $30 range by 2020. 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 (SO ₂ ) emissions and in some regions nitrogen oxide (NO _X ) 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-NO _X 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 NO _X 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 SO ₂ and NO _X 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 SO ₂ and NO _X . 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.

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 SO ₂ and NO _X 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, Luminant and a number of other parties, including 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 filed by Luminant and the other parties pending final review of the petitions for review. In December 2016, the EPA filed a motion seeking a voluntary remand of the rule back to the EPA for further consideration of Luminant's pending request for administrative reconsideration. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration. The stay of the rule (and the emission control requirements) remains in effect, and the EPA is required to file status reports of its reconsideration every 60 days. The retirements of our Monticello, Big Brown and Sandow 4 plants should have a favorable impact on this rulemaking and litigation. 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 SO ₂ , 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, and the identified units receive an annual allowance allocation that is equal to their most recent annual CSAPR SO ₂ allocation. Cumulatively, our units covered by the program are allocated 100,279 allowances annually. Under the rule, a unit that is listed that does not operate for two consecutive years starting after 2018 would no longer receive allowances after the fifth year of non-operation. We believe the retirements of our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO ₂ . For NO _X , 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. The National Parks Conservation Association, the Sierra Club and the Environmental Defense Fund 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 granted a joint motion filed by the EPA and the environmental groups involved to abate the Fifth Circuit Court proceedings until the EPA has taken action on the reconsideration petition and concludes the reconsideration process. In August 2018, the EPA issued a proposed rule affirming the prior BART final rule and seeking comments on that proposal, which were due in October 2018. 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 February 2013, the EPA proposed a rule requiring certain states to remove SIP exemptions for excess emissions during malfunctions or replace them with an affirmative defense. In May 2015, the EPA finalized its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The final rule impacted 36 states, including Texas, Illinois and Ohio, in which we operate. The EPA's final rule would require covered states to remove or replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. Several states (including the State of Texas and the State of Ohio) and various industry parties (including Luminant) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. Before the oral argument was held, in April 2017, the D.C. Circuit Court granted the EPA's motion to continue oral argument and ordered that the case be held in abeyance with the EPA to provide status reports to the D.C. Circuit Court on the EPA's review of the action at 90-day intervals. In October 2018, the EPA partially granted Texas' petition for reconsideration of the Texas SIP call. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the rule as finalized could have a material impact on our results of operations, liquidity or financial condition.

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 SO ₂ 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.

SO ₂ 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 addition, with respect to Monticello and Big Brown, the retirement of those plants should favorably impact our legal challenge to the nonattainment designations in that the nonattainment designations for Freestone County and Titus County are based solely on the Sierra Club modeling, which we dispute, of SO ₂ emissions from Monticello and Big Brown. Regardless, considering these retirements, the nonattainment designations for those counties are no longer supported. 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 have filed lawsuits challenging the 2015 ozone NAAQS. 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 have filed a petition for judicial review challenging the EPA's action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court was completed in October 2018, and oral argument was held in November 2018. 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 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 November 2016, the State of Maryland petitioned the EPA to impose additional NO _X 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. While we cannot predict the outcome of the judicial proceedings, given that the Zimmer facility utilizes SCR technology to control NO _X emissions, we do not believe that the result of these proceedings could cause a material adverse impact on our future financial results.

Illinois Multi-Pollutant Standards (MPS)

In 2007, our MISO coal-fueled generation facilities elected to demonstrate compliance with the Illinois MPS, which require compliance with NO _X , SO ₂ and mercury emissions limits. We are in compliance with the MPS. In October 2017, the Illinois Environmental Protection Agency (IEPA) filed a proposed rule with the Illinois Pollution Control Board (IPCB) that would amend the MPS rule by replacing the two separate group-wide annual emission rate limits that currently apply to our eight downstate Illinois coal-fueled stations with tonnage limits for both SO ₂ (annual) and NO _X (annual and seasonal) that apply to the eight stations as a single group. Under the MPS proposal, allowable annual emissions of SO ₂ and NO _X would be 32 percent lower than under the current rule. All other federal and state air quality regulations, including health-based standards, would remain unchanged and in place. The proposed rule also would impose new requirements to ensure the continuous operation of existing SCR control systems during the ozone season, require SCR-controlled units to meet an ozone season NO _X emission rate limit, and set an additional, site-specific annual SO ₂ limit for our Joppa Power Station. We are supportive of the proposed rule as it would provide operational flexibility to our MISO fleet while also providing a number of regulatory and environmental benefits. IPCB held five hearings on the rule and we expect it to be finalized in 2019.

New Source Review and CAA Matters

New Source Review — Since 1999, the EPA has engaged in a nationwide enforcement initiative to determine whether coal-fueled power plants failed to comply with the requirements of the New Source Review (NSR) and New Source Performance Standard provisions under the CAA when the plants implemented changes. The EPA's NSR initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

In August 2013, the U.S. Department of Justice (DOJ), acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the CAA, including its NSR standards, at our Big Brown and Martin Lake generation facilities. The lawsuit requests (i) the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and (ii) injunctive relief, including an order to apply for pre-construction permits which may require the installation of best available control technology at the affected units. In August 2015, the district court granted Luminant's motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit.

In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in Luminant's favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the Fifth Circuit Court. After the parties filed their respective briefs in the Fifth Circuit Court, the appeal was argued before the Fifth Circuit Court in March 2018. In October 2018, the Fifth Circuit Court affirmed in part, reversed in part, and remanded to the district court. The Fifth Circuit Court's decision held that the district court properly dismissed all of the civil penalties as time-barred. The Fifth Circuit Court further held that the grounds cited by the district court did not support dismissal of the injunctive relief claims at this early stage of the case and remanded the case back to the district court for further consideration. In November 2018, we filed a petition for rehearing en banc on two issues and the EPA's response to that petition is due in February 2019. We believe that we have complied with all requirements of the CAA and intend to continue to vigorously defend against the remaining allegations. An adverse outcome could require substantial capital expenditures that cannot be determined at this time or retirement of the remaining plant at issue, Martin Lake. The retirement of the Big Brown plant should have a favorable impact on this litigation. We cannot predict the outcome of these proceedings, including the financial effects, if any.

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. The NOVs remain unresolved. We are unable to predict the outcome of these matters.

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 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. We filed a motion seeking interlocutory appeal of the court's summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The parties completed briefing on motions for summary judgment on remedy issues in October 2018. In January 2019, the court canceled the bench trial scheduled for March 2019 and denied the parties' motions for summary judgment on remedy issues. In February 2019, the court issued an order that anticipates a trial date at the end of September 2019. We dispute the allegations and will defend the case vigorously. We are unable to predict the outcome of these matters.

Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties, or could result in an order or a decision to retire these plants. While we cannot predict the outcome of these legal proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

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 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 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

In July 2018, the EPA published a final rule that amends certain provisions of the CCR rule that the agency issued in 2015. The 2018 revisions extend closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. The 2018 revisions also (1) establish groundwater protection standards for cobalt, lithium, molybdenum and lead (2) allow authorized state programs to waive groundwater monitoring requirements when there is a demonstration of no potential for contaminant migration, and (3) allow the permitting authority to issue certifications in lieu of a qualified professional engineer. The 2018 revisions became effective in August 2018, and we are continuing to evaluate the impact on our CCR facilities. Also, on August 21, 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule. 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 December 2018, the EPA and petitioners filed cross-motions, with the EPA seeking remand without vacatur and petitioners seeking a partial stay or vacatur of the rule. We have intervened in the litigation and filed a motion in support of the EPA. Briefing on the cross-motions is ongoing. 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 Segment — In 2012, the IEPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. 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 August 2018 court decision, 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, with revised plans submitted 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. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility's National Pollutant Discharge Elimination System permit. Prairie Rivers Network filed a citizen suit in May 2018, 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 Ninth Circuit. We dispute the allegations 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.

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.

If remediation measures concerning groundwater 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 and the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs, as determined by our operations and environmental services teams, are reflected in our AROs.

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 will be approximately $16 million, with the majority of the expenditures in 2020 through 2023 at a group of our Illinois generation facilities. 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.

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, flue desulfurization, fly ash, bottom ash and flue gas mercury control. 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 issued in 2015 and administratively stayed the ELG rule's compliance date deadlines pending ongoing judicial review of the rule. The legal challenges pertaining to bottom ash transport water, flue gas desulfurization wastewater and gasification wastewater have been suspended while the EPA reconsiders the rules.

The EPA issued a final rule in September 2017 postponing the earliest compliance dates in the ELG rule for bottom ash transport water and flue-gas desulfurization wastewater by two years, from November 1, 2018 to November 1, 2020.

Given the EPA's decision to reconsider the bottom ash transport water and flue gas desulfurization wastewater provisions of the ELG rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, and the intertwined relationship of the ELG rule with the CCR rule discussed below, 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.

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.