document: Because of the abundance of coal and its historically low cost, coal-fueled electricity generating units provide a large share of the electricity produced in the United States. In 2012, according to Energy Information Administration (EIA) data, there were 1,309 coal-fueled generating units in the United States, with a total of 309,680 megawatts (MW) of net summer generating capacity—about 29 percent of the total net summer generating capacity in the United States.produced by using other fossil fuels, particularly natural gas and oil; nuclear power; and renewable sources, including hydropower, wind, geothermal, and solar. Historically, coal-fueled generating units have provided about half of the electricity produced in the United States—an amount that has declined in recent years, falling to 37 percent in 2012. In addition to coal, electricity is To address concerns over air pollution, water resources, and solid waste, several environmental laws, including the Clean Air Act, Clean Water Act, and Resource Conservation and Recovery Act, were enacted. As required or authorized by these laws, EPA recently proposed or finalized four key regulations that will affect coal-fueled units. As outlined in table 1, these regulations are at different stages of development and have different compliance deadlines. These four regulations have potentially significant implications for public health and the environment. In particular, EPA projected that, among other benefits, CSAPR would reduce SO emissions by over half in covered states, reducing asthma and related human health impacts. In addition, EPA projected that MATS would reduce mercury emissions by 75 percent from coal-fueled electricity generating units, reducing the impacts of mercury on adults and children. In addition to these four regulations, on June 2, 2014, EPA proposed new regulations to reduce carbon dioxide emissions from existing fossil-fueled generating units that, if finalized, will impact the electricity industry, including coal-fueled generating units, aiming for overall reductions equivalent to 30 percent from 2005 emissions levels by 2030. The proposed regulations include state-specific goals for carbon dioxide emissions and guidelines for states to follow in developing, submitting, and implementing plans to achieve these goals, which would be due in June 2016, although, under some circumstances, a state may submit an initial plan by June 2016 and a completed plan up to 2 years later. In addition to DOE, FERC, and EPA, other key stakeholders have certain responsibilities for overseeing actions power companies take in response to the regulations and have a role in mitigating some potential adverse implications. These other stakeholders include state environmental and electricity regulators and system planners that coordinate planning decisions regarding transmission and generation infrastructure to maintain the reliable supply of electricity to consumers. System planners and operators attempt to avoid reliability problems through advance planning of transmission and, in some cases, generation resources, and coordinating or determining operational decisions such as which generating resources are operated to meet demand throughout the day. The role of a system planner can be carried out by individual power companies or RTOs. System planners’ responsibilities include analyzing expected future changes in generation and transmission assets, such as the retirement of a generating unit; customer demand; and emerging reliability issues. For example, once a power company notifies the system planner that it is considering retiring a generating unit, the system planner generally studies the electricity system to assess whether the retirement would cause reliability challenges and identify long- or short-term solutions to mitigate any impacts. The solutions could include building new generating units, reducing demand in specific areas, building new transmission lines or adding other equipment. DOE, EPA, and FERC have taken initial steps to implement the recommendation we made in our July 2012 report that these agencies develop and document a formal, joint process to monitor industry progress in responding to the four EPA regulations. Since that time, DOE, EPA, and FERC have taken initial steps collectively and individually to monitor industry progress responding to EPA regulations including jointly conducting regular meetings with key industry stakeholders. However, recent and pending actions on the four existing regulations, as well as EPA’s recently proposed regulations to reduce carbon dioxide emissions from existing generating units may require additional monitoring efforts, according to DOE, EPA, and FERC officials. DOE, EPA, and FERC have taken initial steps to implement the recommendation we made in our July 2012 report. In that report we found the agencies had undertaken individual monitoring efforts of varied scale and scope and engaged in informal coordination, but lacked a formal documented process for routinely monitoring industry progress toward compliance with the regulations. As such, we recommended that these agencies develop and document a formal, joint process to monitor industry progress in responding to EPA regulations. We concluded that such a process was needed until at least 2017 to monitor the complexity of implementation and extent of potential effects on price and reliability. Since that time, DOE, EPA, and FERC have taken initial steps collectively to monitor industry progress responding to EPA regulations including jointly conducting regular meetings with key industry stakeholders. Currently, these monitoring efforts are primarily focused on industry implementation in regions with a large amount of capacity that must comply with the MATS regulation—the only one of the four regulations that has taken effect. According to EPA officials, DOE, EPA, and FERC officials have met three times since our July 2012 report to coordinate the efforts under way at each agency to monitor industry’s progress implementing the MATS regulation and other related issues, including EPA’s development of recently proposed regulations to reduce carbon dioxide emissions from existing generating units. In addition, in May 2013, staff from DOE, EPA, and FERC jointly developed a coordination memorandum that was intended to identify how the agencies would work together to address the potential effects of EPA’s regulations on reliability. According to one EPA official, the memorandum was intended to be an evolving document that the agencies would revisit as appropriate, for example, as additional EPA regulations are finalized. These four RTOs include PJM Interconnection, which serves 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; Midcontinent ISO, which serves parts of Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, and Wisconsin, as well as the Canadian province of Manitoba; the Southwest Power Pool, which serves parts of Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas; and the Electric Reliability Council of Texas, which serves parts of Texas. control equipment in use and retrofit plans, and other information such as reliability assessments under way in the region. As part of these meetings, officials told us that the RTOs provided information of varying levels of detail to the agencies, including information on retirement notifications and associated impacts as determined by the reliability studies completed by the RTOs; the status and findings of reliability assessments they conduct; data on the generating capacity of units with planned, announced, or completed retirements and retrofits; and data on planned outages. RTO officials told us they each gathered information about the plans for generating units in the areas they oversee. Officials from several RTOs told us that they gathered this information by surveying owners of generating units to identify, among other things, information on decisions related to retiring or retrofitting specific generating units. According to EPA officials, the agencies’ monitoring and technical assistance efforts are primarily focused on implementation of the MATS requirements because it has taken effect and includes requirements that must be achieved within well-defined time frames. The MATS regulation was finalized in February 2012 and calls for a 3-year compliance period for existing generating units with the deadline of April 16, 2015, but permitting authorities may provide an extra year for certain generating units that request additional time to comply. Agency officials and stakeholders told us that state agencies are generally providing the 1- year extension for generating units—providing these units a total of 4 years to comply. In addition, according to the National Association of Clean Air Agencies (NACAA), as of May 2014, all but 9 of over 100 requests for extensions were granted by the state permitting agencies. In addition to the MATS extension, EPA also provided a mechanism to allow certain units—generating units that are needed to address specific and documented reliability concerns—to request an additional year to come into compliance through the use of Clean Air Act administrative orders—which, if granted, would provide a total of 5 years to comply. According to EPA officials, compliance with the MATS requirements has been less challenging for industry than anticipated, and operators have generally been able to undertake retrofits as part of scheduled maintenance outages; however, certain retrofits, such as the installation of a fabric filter will require additional or longer outages to be completed. According to EPA officials, whether a plant will need to schedule outages for retrofits will depend on a number of factors including the type of controls required for compliance. EPA officials told us they anticipate few administrative orders to be requested. However, if EPA receives a request for an administrative order, EPA has stated in its policy that it will rely on the advice and counsel of reliability experts, including FERC, to identify and analyze reliability risks, but EPA officials will make the final decision on these requests. In May 2012, FERC issued a policy statement detailing how it intends to provide advice to EPA on such requests. In addition to participating in the EPA-facilitated meetings with industry and reviewing information provided from the RTOs through those meetings, DOE, FERC, and EPA have taken other steps to individually monitor or support industry progress implementing EPA regulations. DOE. DOE is offering technical assistance to state public utility commissioners, generating unit owners and operators, and utilities on implementing the new and pending EPA regulations affecting the electric utility industry. Specifically, according to DOE officials and documents, DOE may provide technical information on cost and performance of the various retrofit control technologies; technical information on generation or transmission alternatives for any replacement power needed for retiring generating units; and assistance to public utility commissions regarding any regulatory evaluations or approvals they may have to make on utility compliance strategies. According to agency officials, while DOE offers technical assistance on implementing new and pending EPA rules, DOE has received limited requests for such assistance. EPA. According to EPA officials, EPA has conducted outreach to ensure state agencies understand their ability to provide MATS extensions and EPA officials also review information from NACAA on the status of MATS extension requests. In addition, EPA has updated its power sector modeling tool—a model EPA uses to analyze the impact of policies, regulations, and legislative proposals on the power sector—to reflect MATS requirements along with changes in other market conditions. FERC. FERC officials told us that they monitor information from several sources including the NERC reliability assessments,capacity additions, and information from NACAA on the status of MATS extension requests. In addition, FERC obtained industry information on EIA data on reliability challenges through a technical conference that it convened to obtain information on the effect of recent cold weather events on the RTOs. Recent and pending actions on the four existing regulations, as well as EPA’s recently proposed regulations to reduce carbon dioxide emissions from existing generating units, may require additional agency effort to monitor industry’s progress in responding to the regulations and any potential impacts on reliability. DOE, EPA, and FERC officials told us that, in light of these changes, their coordination efforts may need to be revisited. Specifically, one EPA official noted that the agencies may need to reexamine their coordination efforts, as appropriate, in light of changing conditions, including newly proposed EPA regulations. In addition, according to FERC officials, since not all the regulations have been finalized, conditions will continue to change, making continued monitoring of potential reliability or resource adequacy challenges important. Furthermore, in April 2014, a FERC Commissioner testified before Congress about concerns and uncertainty related to potential reliability and price impacts associated with environmental regulations.Specifically, the Commissioner expressed concerns about the reliability of data on which generating units are retiring and the resources to replace those retiring generating units and called for a more formal review process including FERC, EPA, and others to analyze the specific details of retiring units, as well as the new units and new transmission that will be needed to manage the transition and ensure reliability of the nation’s electricity sector. RTO officials and other industry stakeholders also told us that recent and pending actions on regulations could have impacts on the industry’s ability to reliably deliver electricity. Officials from several RTOs told us that, while widespread reliability concerns are not anticipated, some regions may face reliability challenges including challenges associated with increasing reliance on natural gas. Officials from several RTOs said that their efforts to monitor reliability impacts will include evaluating the recently proposed regulations to reduce carbon dioxide emissions, which may present challenges in the future. In addition, officials from one RTO told us that compliance with new and proposed EPA regulations and an evolving generation portfolio will have significant effects on the industry’s ability to reliably deliver electricity. Officials from this RTO reported that their region is forecasting shortfalls in its reserve margin—additional capacity that exceeds the maximum expected demand to provide for potential backup—in some areas. In addition, these RTO officials and industry stakeholders noted that retirement of coal-fueled generating units may lead to increasing reliance on natural gas, as these generating units are replaced with natural gas fueled generating units, which will require construction of new pipeline and storage infrastructure. As a result, according to officials from one RTO, their region has increased coordination with the natural gas industry through a stakeholder forum and a series of gas infrastructure studies. These officials said that, while relying on natural gas to generate electricity has not historically negatively affected reliability, greater reliance on natural gas may require more consideration of potential fuel-related future reliability challenges. RTO officials and other industry stakeholders also told us recent and pending actions on regulations could have impacts on electricity prices. For example, industry stakeholders told us that the retirements that are occurring or planned are significant and could lead to increased electricity rates in some regions. In addition, as we reported in July 2012, the studies we reviewed estimated that increases in electricity prices could vary across the country, with one study projecting a range of increases from 0.1 percent in the Northwest to an increase of 13.5 percent in parts of the South more dependent on electricity generated from coal. Officials from several RTOs told us that, while they analyze the potential reliability impacts of specific generating units that power companies are considering retiring, they do not analyze the potential market impacts of these retirements on electricity prices or other market factors. In addition, several RTO officials told us they cannot estimate the impacts of these potential retirements on the markets due to the number of factors involved in determining market prices and affecting markets. Based on our discussions with agency officials, FERC, DOE, and EPA are not evaluating the potential impacts of planned retirements or retrofits on electricity prices as part of their monitoring efforts. However, EPA officials told us it uses its power sector modeling tool to analyze the potential impact of new regulations on economic factors including electricity prices and has used the tool to examine the potential impact of the new carbon rule that reflected publicly announced retirements and retrofits at the time of its analysis. According to EPA’s analysis for the recently proposed regulations to reduce carbon dioxide emissions from existing generating units, it projected an increase in the national average retail electricity price between 5.9% and 6.5% in 2020 compared with its base case estimate. According to our analysis, power companies plan to retire a greater percentage of coal-fueled net summer generating capacity and retrofit less capacity with environmental controls than the estimates we reported in July 2012. Specifically, our analysis indicates that power companies retired or plan to retire about 13 percent of coal-fueled net summer generating capacity (42,192 MW) from 2012 through 2025, which exceeds the estimates of 2 to 12 percent of capacity we reported in 2012. In addition, power companies have planned or completed some type of retrofit on about 70,000 MW of net summer generating capacity to reduce SO, NO, or particulate matter from 2012 through 2025, which is less than estimates we reported in 2012. In addition to our analysis of publicly announced retirements and retrofits, RTO officials told us that power companies may take additional steps and provided information on generating units that owners may take steps to retire or retrofit; specifically, about 7,000 MW of additional capacity from 46 generating units may be retired from 2012 through 2025, beyond what we identified in our analysis of SNL data. According to our analysis of SNL data, planned retirements of coal-fueled generating units appear to have increased and are above the high end of the estimates we reported in July 2012. Specifically, power companies retired or plan to retire about 13 percent of coal-fueled net summer generating capacity (42,192 MW from 238 units) from 2012 through 2025. When we reported in July 2012, projections suggested that 2 to 12 percent of coal-fueled capacity may be retired. Based on our analysis of SNL data, power companies retired 100 coal-fueled units from January 2012 to May 2014 with a total of 14,887 MW net summer generating capacity. In addition, based on our analysis of SNL data, power companies have reported plans to retire an additional 138 coal- fueled units with a total of 27,306 MW of net summer generating capacity from June 2014 through 2025. Another recent review also identified higher projected retirements of coal-fueled capacity than estimates we reported in July 2012. Specifically, in April 2014, EIA projected that retirements from 2012 through 2020 could reach approximately 50,000 MW or about 16 percent of net summer generating capacity available at the end of 2012. Consistent with the reasons we had reported for retirements in 2012, some stakeholders we interviewed said that some of these projected retirements may have occurred without the environmental regulations. Specifically, these stakeholders noted that several industry trends may be contributing to the retirement of coal-fueled generating units, including relatively low natural gas prices, increasing prices for coal, and low expected growth in demand for electricity. In addition, in June 2012, we reported that operators of some coal-fueled generating units had entered into agreements with EPA to retire or retrofit units to settle EPA enforcement actions. However, we also reported in July 2012 that, according to some stakeholders, the new environmental regulations may accelerate retirements because power companies may not want to invest in retrofitting units with environmental controls for those units they expect to retire soon for other reasons. About three-quarters of the retirements we identified in our analysis of SNL data are expected to occur by the end of 2015, corresponding to the initial April 2015 MATS compliance deadline (see fig. 1). This level of retirements is significantly more retirements than have occurred in the past; for example, according to our analysis, between 2000 and 2011, 150 coal-fueled units with a total net summer generating capacity of 13,786 MW have been retired. According to our analysis of SNL data, the units that power companies have retired or plan to retire are generally older, smaller, and more polluting, and this is generally consistent with what we reported in October 2012. In addition, we found that many of the units that companies have retired or plan to retire are those that are not used extensively and are geographically concentrated, with some exceptions. Specifically, we found the following: Older. Generating units that power companies have retired or plan to retire are generally older. The fleet of operating coal-fueled units was built over many decades, with most of the capacity currently in service built in the 1970s and 1980s. In particular, from 2012 through 2025, power companies retired or plan to retire about 80 percent of net summer generating capacity from units that were placed in service prior to 1970 (33,419 MW from 213 of the 238 units). However, SNL data indicate that power companies retired or plan to retire some newer generating units, including one generating unit placed into service in 2008. Smaller. Generating units that power companies have retired or plan to retire are generally smaller. Smaller generating units are generally less fuel efficient than larger units and can be more expensive to retrofit, maintain, and operate on a per-MW basis. In particular, smaller units—those less that 300 MW—comprise about 63 percent of the net summer generating capacity that power companies retired or plan to retire from 2012 through 2025 (26,659 MW from 208 of the 238 units). However, some larger generating units are also planned for retirement. In particular, according to our analysis, power companies retired 4 generating units with a net summer generating capacity of over 300 MW from 1990 to 2012, and they retired or plan to retire about 30 such generating units from 2012 through 2025. More polluting. Generating units that power companies retired or plan to retire over the next 3 years emit air pollutants such as SO at generally higher rates than the remaining fleet. According to our analysis, units that were retired or are planned for retirement from 2014 through 2017 emitted on average almost three times as much SO per unit of fuel used at the generating unit in 2013 as units that are not planned for retirement. Similarly, units that were retired or are planned for retirement from 2014 through 2017 emitted on average about 41 percent more NO per unit of fuel used at the generating unit in 2013 than units not planned for retirement. Not used extensively. Most generating units that power companies have retired or plan to retire have not been extensively used in recent years, but other units were used more often. Specifically, according to our analysis, from 2012 through 2025, power companies retired or plan to retire units that comprise about 70 percent of the net summer generating capacity (30,000 MW from 186 of the 238 units) that operated the equivalent of less than half of the hours they were available over the past few years. However, data also indicate that about 13 of the 238 units that companies retired or plan to retire— which represent about 4,200 MW of net summer generating capacity—operated the equivalent of 70 percent or more of the hours they were available over the past few years. Geographically concentrated. Generating units that power companies have retired or plan to retire are concentrated in certain states (see fig. 2). Specifically, about 38 percent of the net summer generating capacity that power companies retired or plan to retire from 2012 through 2025 is located in four states—Ohio (14 percent), Pennsylvania (11 percent), Kentucky (7 percent), and West Virginia (6 percent). In particular, figure 2 shows how completed or planned retirements from 2012 through 2025 are distributed nationwide and how these are concentrated in certain areas. According to our analysis of SNL data, completed or planned retrofits of coal-fueled generating units include less capacity than estimates we reported in July 2012. These retrofits include the use of a wide range of the technologies we reported at that time. As noted in our July 2012 report, operators of generating units were expected to rely on the combined installation of several technologies to comply with the regulations. These technologies include: (1) fabric filters or electrostatic precipitators to control particulate matter; (2) flue gas desulfurization units—also known as scrubbers—or dry sorbent injection units to control SO and acid gas emissions; (3) selective catalytic reduction or selective noncatalytic reduction units to control NO; and (4) activated carbon injection units to reduce mercury emissions. Appendix I includes a description of these controls, how they operate, and their potential capacity to remove pollutants. that power companies have either installed or expect to install a scrubber—generally intended to reduce SO—on about 34,000 MW of net summer generating capacity from 2012 through 2025, an effort that we reported in July 2012 has typically been costly and can take some time to complete. In addition, about 20,000 MW have completed or planned to complete a retrofit to reduce particulates, including about 17,000 MW with completed or planned installations of fabric filters known as “baghouses.” By comparison, in July 2012, we reported that several studies forecasted the steps generating unit owners would take to retrofit units. In particular, EPA estimated that, in response to MATS, companies would retrofit 102,000 MW of generating capacity with fabric filters and 83,000 MW with new scrubbers or scrubber upgrades. In addition, a study by NERC, which collectively examined early versions of all four regulations in 2011, estimated that 576 units that account for about 234,371 MW of capacity would be retrofitted by the end of 2015. We identified two key characteristics of the units that power companies have retrofitted or plan to retrofit as follows: Larger. Most of the net summer generating capacity that have completed or plan to complete a retrofit—about 68 percent—is at larger units with capacity greater than 500 MW. Geographically concentrated. A large share of the net summer generating capacity that has completed or plan to complete a retrofit—about 36 percent—is composed of generating units located in four states: Illinois, Indiana, Kansas, and Texas. In addition, some states have completed or plan to complete more retrofits than others. In particular, seven states (Kansas, Louisiana, New Hampshire, New Mexico, Oregon, South Dakota, and Washington) have completed or plan to retrofit more than half of the net summer generating capacity located in that state. Based on information provided by RTOs, power companies may be considering retiring or retrofitting some additional generating units. In particular, RTO officials provided information on additional generating capacity that power companies have either announced plans to retire or retrofit, or are in the process of considering for a retirement or retrofit. In particular, RTOs identified about 46 coal-fueled generating units that account for about 7,000 MW of additional generating capacity that may be retired from 2012 through 2025, beyond what we identified in our analysis of SNL data. In addition, RTOs identified a total of 260 units that account for about 108,000 MW of generating capacity that have completed or may undertake a retrofit from 2012 through 2025, which may include the capacity identified in our analysis. The electricity sector is in the midst of a significant transition as power companies face decisions on the future of coal-fueled electricity generating units in light of new regulations and changes in the market, such as recent low prices for natural gas, and even though compliance deadlines for three of the regulations remain uncertain, power companies have already identified retirements beyond the range of estimates we reported in 2012. Reliable electricity remains critically important to U.S. homes and businesses and is itself reliant upon the availability of sufficient generating capacity. DOE, EPA, and FERC have taken initial steps to implement our recommendation to establish a joint process to monitor industry’s progress in responding to the four EPA regulations and other factors. However, stakeholders, including a FERC Commissioner, continue to express concerns about reliability and electricity prices. Furthermore, proposed regulations focused on reducing emissions of carbon dioxide from the electricity sector, when finalized, may pose additional challenges for coal-fueled generating units. The initial coordination efforts now under way across the three agencies are an important tool for understanding and monitoring the potential effects of EPA regulations and other factors on the electricity sector. However, consistent with our recommendation in 2012, careful monitoring and coordination by the federal agencies incorporating the views of other stakeholders such as RTOs will be even more important over the next several years as key regulations are finalized and implemented. We are not making new recommendations in this report. We provided a draft of this report to DOE, EPA, and FERC, for review and comment. In written comments from DOE, EPA, and FERC, reproduced in appendixes II, III, and IV respectively, the three agencies generally concurred with our analysis. The agencies stated that they will continue to monitor the progress of industry implementation of the regulations and coordinate with one another to address potential reliability challenges. Specifically, DOE stated that these coordination efforts have primarily focused on MATS and may be revisited as they work with industry to monitor compliance with other EPA regulations. EPA stated that it will monitor compliance with all of the rules, as appropriate, to ensure that reliability is not put at risk. FERC stated that it is working with industry to explore reliability issues stemming from new and pending environmental rules for the power sector, and that it will continue to monitor industry’s progress implementing these rules and will coordinate with DOE, EPA, and industry. We continue to believe it is important that these agencies jointly monitor industry’s progress in responding to the EPA regulations and fully document these steps as we recommended in 2012. As agreed with your office, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies to the appropriate congressional committees, the Secretary of Energy, the Administrator of the EPA, the Chairman of FERC, and other interested parties. In addition, the report will be available at no charge on the GAO website at http://www.gao.gov. If you or your staff members have any questions about this report, please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report. GAO staff members who made major contributions to this report are listed in appendix V. How it works An induced electrical charge removes particles from flue gas. Fabric filter (commonly referred to as a “baghouse”) Flue gas passes through tightly woven fabric filter “bags” that filter out the particulates. Flue gas desulfurization unit (commonly referred to as a “scrubber”) Wet flue gas desulfurization units inject a liquid sorbent slurry, such as a limestone slurry, into the flue gas to form a wet solid that can be disposed of or sold. Dry flue gas desulfurization units inject a dry sorbent, such as lime, into the flue gas to form a solid byproduct that is collected. Coal combustion conditions are adjusted so less NO is formed. For SCR, ammonia is injected into flue gas to react with NO to form nitrogen (N) and water and uses a catalyst to enhance the reaction. For SNCR, ammonia or urea is injected into flue gas to react with NO as well, but does not use a catalyst. Activated carbon injection units Powdered activated carbon sorbent is injected into flue gas, binds with mercury, and is collected in particulate matter control device. In addition to the individual named above, Jon Ludwigson (Assistant Director), Janice Ceperich, Margaret Childs, Philip Farah, Quindi Franco, Cindy Gilbert, Richard Johnson, Armetha Liles, and Alison O’Neill made key contributions to this report.
summary: EPA recently proposed or finalized four regulations affecting coal-fueled electricity generating units, which provide about 37 percent of the nation's electricity supply. These regulations are the: (1) Cross-State Air Pollution Rule; (2) Mercury and Air Toxics Standards; (3) Cooling Water Intake Structures regulation; and (4) Disposal of Coal Combustion Residuals regulation. In 2012, GAO reported that, in response to these regulations and other factors such as low natural gas prices, companies might retire or retrofit some units. GAO reported that these actions may increase electricity prices and, according to some stakeholders, may affect reliability–the ability to meet consumers' demand—in some regions. In 2012, GAO recommended that DOE, EPA, and FERC develop and document a formal, joint process to monitor industry's progress responding to these regulations. In June 2014, EPA proposed new regulations to reduce carbon dioxide emissions that will also affect these units. GAO was asked to update its 2012 report. This report examines (1) agencies' efforts to respond to GAO's recommendation and (2) what is known about planned retirements and retrofits. GAO reviewed documents, analyzed data, and interviewed agency officials and stakeholders. The Department of Energy (DOE), the Environmental Protection Agency (EPA), and the Federal Energy Regulatory Commission (FERC) have taken initial steps to implement a recommendation GAO made in 2012 that these agencies develop and document a joint process to monitor industry's progress in responding to four proposed or finalized EPA regulations affecting coal-fueled generating units. GAO concluded that such a process was needed until at least 2017 to monitor the complexity of implementation and extent of potential effects on price and reliability. Since that time, DOE, EPA, and FERC have taken initial steps to monitor industry progress responding to EPA regulations including jointly conducting regular meetings with key industry stakeholders. Currently, these monitoring efforts are primarily focused on industry's implementation of one of four EPA regulations—the Mercury and Air Toxics Standards—and the regions with a large amount of capacity that must comply with that regulation. Agency officials told GAO that in light of EPA's recent and pending actions on regulations including those to reduce carbon dioxide emissions from existing generating units, these coordination efforts may need to be revisited. According to GAO's analysis of public data, power companies now plan to retire a greater percentage of coal-fueled generating capacity and retrofit less capacity with environmental controls than the estimates GAO reported in July 2012. About 13 percent of coal-fueled generating capacity—42,192 megawatts (MW)—has either been retired since 2012 or is planned for retirement by 2025, which exceeds the estimates of 2 to 12 percent of capacity that GAO reported in 2012 (see fig.). The units that power companies have retired or plan to retire are generally older, smaller, more polluting and not used extensively, with some exceptions. For example, some larger generating units are also planned for retirement. In addition, the capacity is geographically concentrated in four states: Ohio (14 percent), Pennsylvania (11 percent), Kentucky (7 percent), and West Virginia (6 percent). GAO's analysis identified about 70,000 MW of generating capacity that has either completed some type of retrofit to reduce sulfur dioxide, nitrogen oxides, or particulate matter since 2012 or plan to complete one by 2025, which is less than the estimate of 102,000 MW GAO reported in 2012. GAO is not making new recommendations but believes it is important that these agencies jointly monitor industry progress and fully document these steps as GAO recommended in 2012. The agencies concurred with GAO's findings.