EPA Regulations and Electricity: Better Monitoring by Agencies Could Strengthen Efforts to Address Potential Challenges

EPA recently proposed or finalized four regulations affecting coal-fueled electricity generating units, which provide almost half of the electricity in the United States: (1) the Cross-State Air Pollution Rule; (2) the Mercury and Air Toxics Standards; (3) the proposed Cooling Water Intake Structures regulation; and (4) the proposed Disposal of Coal Combustion Residuals regulation. Power companies may retrofit or retire some units in response to the regulations. EPA estimated two of the regulations would prevent thousands of premature deaths and generate $160-$405 billion in annual benefits. Some stakeholders have expressed concerns that these regulations could increase electricity prices and compromise reliability—the ability to meet consumers' demand. FERC and others have oversight over electricity prices and reliability. DOE can order a generating unit to run in certain emergencies. GAO was asked to examine: (1) actions power companies may take in response to these regulations; (2) their potential electricity market and reliability implications; and (3) the extent to which these implications can be mitigated. GAO reviewed agency documents, selected studies, and interviewed stakeholders.

It is uncertain how power companies may respond to four key Environmental Protection Agency (EPA) regulations, but available information suggests companies may retrofit most coal-fueled generating units with controls to reduce pollution, and that 2 to 12 percent of coal-fueled capacity may be retired. Some regions may see more significant levels of retirements. For example, one study examined 11 states in the Midwest and projected that 18 percent of coal-fueled capacity in that region could retire. EPA and some stakeholders GAO interviewed stated that some such retirements could occur as a result of other factors such as lower natural gas prices, regardless of the regulations. Power companies may also build new generating units, upgrade transmission systems to maintain reliability, and increasingly use natural gas to produce electricity as coal units retire and remaining coal units become somewhat more expensive to operate.

Available information suggests these actions would likely increase electricity prices in some regions. Furthermore, while these actions may not cause widespread reliability concerns, they may contribute to reliability challenges in some regions. Regarding prices, the studies GAO reviewed estimated that increases 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. According to EPA officials, the agency’s estimates of price increases would be within the historical range of price fluctuations, and projected future prices may be below historic prices. Regarding reliability, these actions are not expected to pose widespread concerns but may contribute to challenges in some regions. EPA and some stakeholders GAO interviewed indicated that these actions should not affect reliability given existing tools. Some other stakeholders GAO interviewed identified potential reliability challenges. Among other things, it may be difficult to schedule and complete all retrofits to install controls and to resolve all potential reliability concerns associated with retirements within compliance deadlines.

Existing tools could help mitigate many, though not all, of the potential adverse implications associated with the four EPA regulations, but the Federal Energy Regulatory Commission (FERC), Department of Energy (DOE), and EPA do not have a joint, formal process to monitor industry’s progress in responding to the regulations. Some tools, such as state regulatory reviews to evaluate the prudence of power company investments, may address some potential price increases. Furthermore, tools available to industry and regulators, as well as certain regulatory provisions, may address many potential reliability challenges. However, because of certain limitations, these tools may not fully address all challenges where generating units needed for reliability are not in compliance by the deadlines. FERC, DOE, and EPA have responsibilities concerning the electricity industry, and they have taken important first steps to understand these potential challenges by, for example, informally coordinating with power companies and others about industry’s actions to respond to the regulations. However, they have not established a formal, documented process for jointly and routinely monitoring industry’s progress and, absent such a process, the complexity and extent of potential reliability challenges may not be clear to these agencies. This may make it more difficult to assess whether existing tools are adequate or whether additional tools are needed.

GAO recommends, among other things, that FERC, DOE, and EPA take additional steps to monitor industry’s progress in responding to the regulations. DOE and EPA agreed with this recommendation, and FERC disagreed with this and another recommendation. GAO continues to believe that it is important for FERC to take the recommended actions.

Coal is an abundant and widely used fuel source in the United States,  producing about 42 percent of the nation’s electricity supply in 2011.  Coal-fueled power plants have historically been among the least costly  sources of electricity in the country. However, burning coal and other  fossil fuels (i.e., natural gas and oil) to produce electricity is associated  with human health and environmental concerns. For example, fossil fuel  electricity generating units are among the largest emitters of sulfur dioxide  (SO) and nitrogen oxides (NO), which have been linked to respiratory  illnesses and acid rain and which may travel great distances and affect air  quality in states downwind from generating units—downwind states. In  2008, the last year for which EPA has such comprehensive information,  coal-fueled units emitted about 48 percent of the nation’s mercury, a  hazardous air pollutant and heavy metal linked to neurological disorders  in children and harm to wildlife  In addition, coal-fueled generating units  emit large quantities of carbon dioxide, the primary greenhouse gas  contributing to climate change, and can use significant quantities of water  and create large amounts of waste products that require disposal.  .

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, the Environmental Protection  Agency (EPA), the primary federal agency responsible for implementing  many of the nation’s environmental laws, recently proposed or finalized  four key regulations that will affect coal-fueled units. emissions by 73 percent and NO  emissions by over half in covered states, reducing asthma and related  human health impacts. In addition, EPA projects 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 2016,  EPA estimates that the final versions of MATS and CSAPR could  generate $160 billion to $405 billion in monetized annual benefits (in 2011  year dollars), preventing tens of thousands of premature deaths and  reducing pollution-related illnesses.

These four regulations could also have significant implications for the  electricity industry. Generating units fueled by coal—which comprise a  large portion of the national electricity supply—are expected to be  affected by the four proposed regulations. Power companies might retrofit  some generating units with controls to reduce pollutants and, when it is  not economic to retrofit, may retire some generating units, according to  EPA. Several representatives from power companies and officials from  federal and state regulatory agencies have expressed concerns that, as  companies incur additional costs in responding to these regulations, and  as the electricity supply is affected by generating unit retirements,  electricity prices could increase and reliability—the ability to meet  consumers’ electricity demand—could be compromised.

Federal agencies and other stakeholders have some responsibilities for  overseeing actions power companies take in response to the regulations  and have a role in mitigating some potential adverse implications. The  Federal Energy Regulatory Commission (FERC) is generally responsible  for ensuring that certain electricity and transmission prices are “just and  reasonable,” as well as approving and enforcing standards for reliability in  the bulk power system––the interconnected transmission system  combined with the electric power from generating units needed to  maintain the system. The Department of Energy (DOE) works to  modernize the electricity system, enhance the security and reliability of  the nation’s energy infrastructure, and facilitate recovery from any  disruptions. DOE also has authority to compel generating units to produce  electricity in certain emergency situations. Other stakeholders also play  key roles, such as 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.President directed EPA to, among other things, promote early,  coordinated, and orderly planning and execution of the measures needed  to implement MATS while maintaining electricity reliability, including  coordination with DOE, FERC and others.

In a December 2011 memorandum, the  In this context, you asked us to provide information on the implications of  the four key recently proposed or finalized EPA regulations. Our  objectives were to examine: (1) what available information indicates about  actions power companies may take at coal-fueled generating units in  response to the four key EPA regulations; (2) what available information  indicates about these regulations’ potential implications on the electricity  market and reliability; and (3) the extent to which EPA, FERC, DOE, and  other stakeholders can mitigate adverse electricity market and reliability  implications, if any, associated with requirements in these regulations.

To examine what available information indicates about actions power  companies may take in response to these regulations and their potential  market and reliability implications, we (1) selected for review 12 studies of  companies’ projected responses to the regulations and the potential  impacts of these responses and (2) analyzed data from Ventyx Velocity  Suite on electricity generating units. We considered several factors in  selecting studies, including how closely they reflect the four regulations,  and we assessed the reasonableness of the studies’ assumptions and  methodologies. The studies we selected were carried out by EPA, the  Energy Information Administration (EIA), system planners, research  organizations, and a consulting firm.differences between study assumptions and the regulations, which we  note in the text where appropriate. The actual pricing and reliability  implications of these regulations will depend on various uncertain factors,  such as future market conditions and the ultimate regulatory  requirements, but we determined that these studies were reasonable for  describing what is known about the range of potential implications of the   In some cases, we identified  four regulations. We used data from Ventyx Velocity Suite, as of April 9,  2012, to describe coal-fueled generating units and to provide information  on historic and planned retrofits and retirements of such units. Ventyx  Velocity Suite is a proprietary database containing consolidated energy  data from EIA, EPA, and other sources. Information regarding planned  retrofits and retirements reflect publicly reported plans as identified by  Ventyx. As plans may change, actual future retrofits and retirements may  differ from the data in these plans. To examine the extent to which  agencies and other stakeholders can mitigate any adverse implications,  we interviewed officials at the EPA, FERC, and DOE, and reviewed  relevant documents. To address all three objectives, we summarized the  results of semistructured interviews with a nonprobability sample of 33  stakeholders, including officials from EPA, FERC, and DOE;  representatives of power companies; regional transmission system  operators; state regulators; and researchers. We selected these  stakeholders to be broadly representative of differing perspectives on  these issues based on recommendations from EPA, FERC, DOE,  industry associations and such factors as the percentage of companies’  generating capacity that is coal-fueled. We provided a preliminary list of  the stakeholders we intended to interview to FERC and EPA, and we  incorporated their suggestions in considering stakeholders where  appropriate. Because we used a nonprobability sample, the views of  these stakeholders are not generalizable to all potential stakeholders but  they provide illustrative examples. Appendix I provides additional  information on our scope and methodology, appendix II lists the  stakeholders we interviewed, and appendix III lists the studies we  reviewed.

We conducted this performance audit from July 2011 to July 2012 in  accordance with generally accepted government auditing standards.  Those standards require that we plan and perform the audit to obtain  sufficient, appropriate evidence to provide a reasonable basis for our  findings and conclusions based on our audit objectives. We believe that  the evidence obtained provides a reasonable basis for our findings and  conclusions based on our audit objectives.

This section describes the role of coal in generating electricity, the four  key EPA regulations, actions involved in maintaining electric reliability,  and federal and state government roles in electricity markets.

Because of the abundance of coal and its historically low cost, many coal- fueled electricity generating units were built and these provide a large  share of the electricity produced in the United States. In 2010, there were  1,396 coal-fueled generating units in the United States, with a total  316,800 megawatts (MW) of net summer generating capacity—about 30  percent of the total generating capacity in the United States. In addition  to coal, electricity is produced by burning other fossil fuels, particularly  natural gas and oil; using nuclear power through nuclear fission; and  using renewable sources, including hydropower, wind, geothermal, and  solar.

Coal is the largest source of electricity generation, but the percentage of  electricity produced using coal has declined––from 53 percent in 1990 to  about 42 percent in 2011—and coal’s role in the electricity system is  changing due to a number of factors. According to some stakeholders we  interviewed, several broad trends are affecting the use of coal and  contribute to the retirement of coal-fueled generating units. First, in some  areas of the country, it has become less economically attractive to use  coal to produce electricity, as the regional prices of coal have increased,  and prices for natural gas have fallen and the availability of natural gas  has increased. Second, demand for electricity is projected to grow slowly  in some areas, limiting the need for new power plants. Third, a portion of  coal-fueled generating units are old—73 percent of coal-fueled capacity  was 30 years or older at the end of 2010—and less efficient than other  sources. Despite these trends, coal is expected to continue to be a major  fuel source in the future, with the EIA recently projecting coal to account  for about 39 percent of the United States’ electricity by 2035 with current  policies. We are examining these issues and expect to report later this  year on how the use of coal in electricity production is expected to  change.

Reliance on coal varies significantly around the country. As shown in  figure 1, in 2010, coal was used to generate the majority of electricity  produced in several states, particularly in the Midwest, while little of the  electricity generated in states on the West Coast and in New England  was from coal.

Four recent key EPA regulations address air pollution from electricity  generating units, disposal of coal combustion residuals from certain  generating units, and death of aquatic life as a result of water withdrawal  for use for cooling at certain electricity generating units. As outlined in  table 1, these regulations are at different stages of development, have  different compliance deadlines, and EPA estimates that they will generate  significant monetized benefits and costs.

Coal-fueled electricity generating units are a major source of air pollution  in the United States. Burning coal for electricity production results in the  emission of pollutants such as SO, NO, mercury and other metals, and  acid gases. Coal-fueled electricity generating units are among the largest  emitters of these pollutants. This air pollution has adverse health and  environmental effects. For example, SO emissions contribute to  the formation of fine particulate matter, and NO contributes to the  formation of ozone. Fine particulate matter may aggravate respiratory and  cardiovascular diseases and is associated with asthma attacks and  premature death. Ozone can inflame lung tissue and increase  susceptibility to bronchitis and pneumonia. In addition to affecting health,  SO and NO reduce visibility and contribute to acid rain, which can  acidify streams and change the nutrient balance in coastal waters and  large river basins, affecting their ability to support fish and other wildlife.  Mercury is a toxic element, and human intake of mercury, for example,  through consumption of fish that ingested the mercury, has been linked to  a wide range of health ailments. In particular, mercury can harm fetuses  and cause neurological disorders in children, resulting in, among other  things, impaired cognitive abilities. Other toxic metals emitted from power  plants, such as arsenic, chromium, and nickel can cause cancer. Acid  gases cause lung damage and contribute to asthma, bronchitis, and other  chronic respiratory diseases, especially in children and the elderly.

The Clean Air Act requires EPA to establish national ambient air quality  standards that states are primarily responsible for attaining. States  generally develop state implementation plans that detail how the  standards will be attained and maintained. In addition, the act’s Good  Neighbor provision requires state implementation plans to prohibit  emissions of air pollutants in amounts that will contribute significantly to  nonattainment or interference with maintenance of a national ambient air  quality standard in any other state. Electricity generating units contribute  to pollution that affects the ability of downwind states to attain and  maintain these standards because some of these pollutants may travel in  the atmosphere hundreds or thousands of miles from the areas where  they originate. If a state fails to develop and submit a state  implementation plan that satisfies all Clean Air Act requirements,  including the Good Neighbor provision, by specified deadlines, EPA is  required to issue a federal implementation plan. EPA issued regulations  interpreting and clarifying the Good Neighbor provisions in 1998 and  2005, but a federal court found the 2005 regulation and its federal  implementation plans to be unlawful. Although the court remanded the  2005 regulation to EPA in 2008, it allowed the regulation and its federal  implementation plans to remain in effect until EPA issued a replacement  regulation. and NO emissions that contribute significantly to  downwind nonattainment of certain national ambient air quality standards. The CAIR  federal implementation plans issued in 2006 regulate electricity generating units in the  covered states and achieve CAIR’s emissions reductions requirements. The court allowed  CAIR and its federal implementation plans to remain in effect until replaced because, even  with flaws, they would at least temporarily preserve the environmental values covered by  CAIR. the control period could be subject to financial penalties and must  surrender two allowances for each excess ton of pollution emitted. EPA  projects that CSAPR would reduce SO  emissions by 54 percent in the covered states and could avoid 13,000 to  34,000 premature deaths, generating $128 to $299 billion in benefits, with  $853 million in costs in 2014. The control periods for some of the trading  programs were scheduled to begin on January 1, 2012, but the U.S.  Court of Appeals for the D.C. Circuit stayed CSAPR on December 30,  2011. Depending on how the court rules, CSAPR may change.

The Clean Air Act also requires EPA to study the public health hazards  from electricity generating units’ emissions of mercury and other  hazardous air pollutants and to regulate those emissions under section  112 if it finds that such regulation is “appropriate and necessary.” EPA  made such a finding regarding certain electricity generating units in 2000  but did not issue a regulation under section 112. In 2005, EPA reversed  this finding and finalized a regulation under section 111 of the Clean Air  Act regulating mercury emissions from certain electricity generating units,  which a federal court later struck down. Pursuant to a settlement  agreement to resolve a lawsuit for failing to meet the statutory deadline  for issuing a section 112 regulation, EPA published the final MATS  regulations in February 2012. Among other things, MATS establishes  numerical emissions limitations for mercury, filterable particulate matter  (as a surrogate for all toxic nonmercury metal pollutants), and hydrogen  chloride (as a surrogate for all toxic acid gas pollutants) at certain new  and existing generating units. All of the numerical limitations applicable to  existing units except one are set at the average emissions limitation  achieved by the best performing 12 percent of existing sources.  Generating units would have 3 years, until April 2015, to comply with  MATS and could receive up to a 1-year extension from permitting  authorities (typically state or local authorities), if necessary for the  installation of controls. EPA also outlined a mechanism to allow units that  are needed to address specific and documented reliability concerns to  receive Clean Air Act administrative orders to provide up to an additional  year to come into compliance. EPA estimates that the final standards  would reduce mercury emissions from coal-fueled electricity generating  units by 75 percent and reduce hydrogen chloride emissions by 88  percent. EPA estimated the benefits of MATS would be $39 to $96 billion  with costs of $10.2 billion in 2016. Petitions for review of MATS have  been filed in the U.S. Court of Appeals for the D.C. Circuit, but the court  has not yet issued a ruling. Depending on how the court rules, MATS may  change.

Burning coal to produce electricity creates combustion residuals, such as  coal ash, which represent one of the largest waste streams in the United  States. These residuals contain contaminants like mercury, cadmium, and  arsenic that are associated with cancer and various other serious health  effects. Coal combustion residuals can be disposed of wet (mixed with  water) in large surface impoundments, or dry in landfills. that many landfills and impoundments lack liners and groundwater  monitoring systems, and without proper protections, contaminants can  leach into groundwater and migrate to drinking water sources, posing  significant public health concerns.

Some coal combustion residuals have beneficial uses; for example, they can be used in  the manufacture of such construction materials as concrete or wallboard. According to  EPA documentation, about 37 percent of coal combustion residuals are used beneficially.  EPA did not propose to regulate the beneficial use of coal combustion residuals, though  some industry officials have expressed concerns that designating residuals as hazardous  could negatively impact beneficial uses. disposal of nonhazardous solid waste to protect human health and the  environment. In June 2010, to address risks from the disposal of coal  combustion residuals generated at electricity generating units, EPA  proposed CCR to regulate coal combustion residuals for the first time.  EPA co-proposed two alternative regulations. Under the first, EPA would  list residuals as a special waste and regulate them as a hazardous waste  by establishing requirements for their management from generation to  disposal. Under the second option, EPA would regulate coal combustion  residuals as nonhazardous solid waste and establish national minimum  standards for their disposal in surface impoundments or landfills.  Regulation as a special waste would occur through a federal or  authorized state permitting program with requirements for its storage,  transport, and disposal, among other things. Regulation as a special  waste would also allow for federal enforcement. Regulation as a  nonhazardous solid waste would not require the establishment of a permit  program and would not be federally enforceable. Instead, states or private  parties could bring lawsuits against alleged violators. EPA estimated the  annualized benefits of its special waste option would be $207 to $1,342  million with $1,549 million in annualized costs and that the nonhazardous  waste option would generate annualized benefits of $88 to $596 million  with $606 million in annualized costs.issuing a final CCR regulation.

Coal and other types of electricity generating units often draw in large  volumes of water from nearby rivers, lakes, or oceans to use for cooling,  which can damage aquatic life. Thermoelectric generating units are the  largest water use category by sector, using 201 billion gallons per day in  2005, the most recent year for which data were available. Depending on  how a generating unit’s cooling system is designed, drawing in water for  cooling can result in fish and other aquatic life being impinged—trapped— against intake screens used to filter out solid matter, as well as  entrained—drawn into—the generating unit with the cooling water.  According to EPA, generating units kill hundreds of billions of aquatic  organisms in U.S. waters each year, including fish, crustaceans, marine  mammals, and other aquatic life.

EPA first issued a regulation implementing section 316(b) in 1976, but that regulation  was struck down by a federal appeals court in 1979. EPA has issued two other regulations  implementing section 316(b) that are currently in effect: the Phase I regulation that  governs new power plants and manufacturing facilities and the Phase III regulation that  governs new offshore oil and gas facilities. capacity would be affected by the proposed regulation.regulating cooling water intake structures, EPA estimates increased  harvests in recreational and commercial fisheries, improved ecosystem  function, and reduced harm to threatened and endangered species,  among other benefits. EPA estimated the annualized benefits of its  proposed regulation to be $18 million with costs of $397 million. EPA is  required by a settlement agreement to sign a final regulation no later than  July 27, 2012.

Planning and Day-to-Day Actions Involved in Maintaining Electric Reliability

Electric reliability refers to the ability to meet the needs of end-use  customers even when unexpected generating equipment failures or other  factors affect the electricity system.multiple ways:   Reliability challenges can arise in

Resource adequacy challenges. These arise when there are  inadequate resources—generation, transmission, and others—to  meet the electricity needs of end-use customers. To avoid resource  adequacy challenges, system planners typically take steps to ensure  that generating capacity exceeds the maximum expected demand by  a certain margin, referred to as a “reserve margin.”

System security challenges. These arise because of a disturbance,  such as an electrical short, or the loss of a system component, such  as a generating unit that is needed at a specific location to maintain  the electricity grid’s voltage and frequency or to help restart the  electricity system in the case of a blackout. To avoid system security  challenges, system operators make real-time changes in the  operation of the electricity system, for example, by increasing or  decreasing the amount of electricity generated in particular locations   or by changing power flows on the transmission system in order to  maintain suitable operating conditions.

System planners attempt to avoid reliability problems through advance  planning of transmission and, in some cases, generation resources. The  role of a system planner can be carried out by individual power  companies or regional entities called Regional Transmission  Organizations (RTO). Figure 3 shows the territories of the seven RTOs  in the United States. 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 system planner learns that a power  company intends to retire a generating unit, the system planner generally  studies the electricity system to assess whether the retirement would  cause reliability challenges and identify solutions to mitigate any impacts.  The solutions could be in the form of replacement capacity (generation or  demand-side resources) and new transmission lines or other equipment,  each with its own associated permitting and construction timelines.

When reliability challenges cannot be avoided through prior planning,  system operators take measures to resolve the problem by rebalancing  supply and demand. The role of the system operator is also fulfilled by  different entities, including individual power companies and RTOs. In the  event of an urgent reliability challenge, system operators may take  immediate steps to lower demand through public appeals to reduce use;  interrupting or lowering electricity supply to customers who have  negotiated prior agreements with the power company, which are referred  to as reliability-driven demand-response programs; as well as rotating  blackouts of limited duration. For example, during a period of sustained  high summer temperatures in 2011, the system operator in Texas called  upon the public to reduce electricity use during hours of peak demand to  prevent the need for rotating blackouts. When reliability challenges  cannot be adequately managed by system operators, unplanned,  uncontrolled interruption of customer’s electricity use can occur. These  interruptions may be confined to a localized area or widespread. For  example, in August 2003, an electricity blackout affected millions of  people across eight U.S. states and parts of Canada when, among other  things, system operators were unable to keep outages in northern Ohio  from cascading to interconnected portions of the electric grid. In some  areas, power was lost for several days.

Federal and State Government Roles in Electricity Markets

The potential impact of retrofits and retirements on electricity prices and  reliability is generally overseen by the federal regulator, FERC; state  regulators, including state public utility commissions; and others.

At the federal level, among other things, FERC is responsible for ensuring  that the rates, terms and conditions of services for wholesale electricity  sales and transmission in interstate commerce—which includes  wholesale electricity prices—are just and reasonable and not unduly  discriminatory or preferential. In some parts of the country, FERC does  this by overseeing the design and operation of organized electricity  markets—markets for electricity and other services intended to promote  the reliable management of the grid—to ensure these markets are  competitive and will result in just and reasonable electricity prices.

Organized markets are administered by RTOs, the same independent  entities that serve as system planners and operators in some regions.  These electricity markets are designed to ensure an adequate supply of  electricity at reasonable prices, and the markets are routinely examined  by independent entities and FERC to ensure they are competitive and  free of manipulation.

As a part of its responsibility for ensuring just and reasonable rates,  FERC has broad authority to oversee RTO rules related to electricity  transmission, markets, and other areas. These rules may include  requirements about how the transmission planning process is managed,  the terms and conditions under which transmission service is provided,  when and how the operator of a generating unit should notify the RTO of  a planned retirement, and steps the RTO will take in scheduling outages,  among other things. For example, RTOs typically require power  companies to notify them when the companies plan to retire a generating  unit. The time frame for this notification generally varies from 45 days to  approximately 180 days. RTOs have an internal process in which  stakeholders review, modify, and may vote on proposed changes to rules.  If changes are agreed upon by the RTO’s stakeholders—power  companies, transmission owners, and users of electricity, among others— the RTO may propose them to FERC for approval.own review of proposed changes to RTO tariffs and market rules to  ensure they promote just and reasonable rates including, where relevant,  reliability requirements. In some cases, FERC may also proactively  review RTO market rules and order any changes to ensure they are just,  reasonable, and not unduly discriminatory or preferential. FERC is also  responsible for examining whether reliability must-run agreements— agreements to provide nonmarket based payments to power companies  with generating units that are not economical to operate but are critical to  the reliability of the electricity grid—are at reasonable rates. These   FERC conducts its  payments would cover the cost of keeping such units operational past  when companies were planning to retire them.

The role of state governments in overseeing electricity prices varies  across the country. In some areas, referred to as “traditionally regulated  markets,” state public utility commissions—which generally aim to ensure  retail electricity rates are just and reasonable—review power companies’  requests to recover the costs of investments in new generating units,  distribution lines and other system upgrades. Once a state public utility  commission approves a power company’s request, consumer retail prices  are adjusted to recover the power companies’ costs plus a rate of  return. For companies in traditionally regulated markets, their  investments in controls to comply with EPA regulations would have to be  approved by public utility commissions for the companies to adjust their  rates to include these costs. In other parts of the country, referred to as  “restructured markets,” electricity is sold by multiple companies  competing with each other. In these areas, public utility commissions play  a more limited role in overseeing generation. Consumers pay competitive  retail electricity rates based on the price of electricity as determined in  FERC-regulated wholesale markets. Many electricity generating  companies have received authority from FERC to sell power at market- based rates and, in restructured markets, these companies would aim to  recover the costs of any investments made to comply with EPA  regulations through wholesale sales of electricity, but their ability to do so  depends on overall supply and demand conditions, which determine the  prices they can receive.

Under the Energy Policy Act of 2005, FERC is responsible for approving  and enforcing standards to ensure the reliability of the bulk power system.  FERC certified NERC to develop and enforce these reliability standards,  subject to FERC review. These standards outline general requirements  for planning and operating the bulk power system to ensure reliability. For  example, one reliability standard requires that system planners plan and  develop their systems to meet the demand for electricity even if  equipment on the bulk power system, such as a single generating unit or  transformer, is damaged or otherwise unable to operate. With respect to  MATS, EPA has stated that it will rely on the advice and counsel of  reliability experts, including FERC, to identify and analyze reliability risks  when owners request a Clean Air Act administrative order to provide units  with up to an additional year for compliance with MATS. FERC recently  issued a policy statement detailing how it intends to provide advice to  EPA on such requests.

In general, neither FERC or NERC, nor the system planners can require  companies to build generation or compel existing generation to operate,  but DOE can order the generation of electricity in limited circumstances.  Specifically, in certain emergencies, section 202(c) of the Federal Power  Act authorizes DOE to order, among other things, the generation of  electricity that in its judgment will best meet the emergency and serve the  public interest. DOE has used this authority in the past to, among other  things, ensure electricity could be provided to the District of Columbia in  the event of a transmission line failure, as well as to provide electricity to  customers during the California energy crisis. Furthermore, some state  public utility commissions may require power companies to ensure they  can provide adequate levels of generation to meet the demand of  customers in their service territory.

Power Companies Are Expected to Retrofit or Retire Units and Take Other Actions

According to available information, there is uncertainty regarding how  power companies will respond to the four key EPA regulations, though  companies are expected to retrofit most coal-fueled generating units with  controls, retire other units, and take additional actions.

It Is Uncertain How Power Companies Will Respond to Key EPA Regulations

It is unclear how power companies will respond to the four key EPA  regulations, in part because there is uncertainty about the regulations  themselves and other factors affecting the industry, including future  natural gas prices. Analysts that have studied how power companies may  respond to the regulations have made different assumptions regarding  these factors, which affect power companies’ assessments of whether to  make additional investments in coal-fueled generating units such as  investments that may be needed to respond to the four key regulations.

Regarding the regulations, the requirements and deadlines they may  establish for generating units are somewhat uncertain, especially for the  proposed regulations. This is because the final CCR and 316(b)  regulations might differ from the proposed regulations and because of  current and potential future legal challenges. For example, CSAPR and  MATS—the two regulations that have been finalized—face legal  challenges and may change depending on how the court rules. In  addition, some of the regulatory requirements, such as some aspects of  316(b), will not be specified until the relevant permits are issued.  Furthermore, several bills have been introduced in Congress that would  affect some or all of the regulations. Some power companies may delay  taking actions to respond to these regulations until there is additional  certainty about their final regulatory requirements.

Several other factors also contribute to the uncertain environment in  which power companies will respond to the new regulations. Among  these is uncertainty about the future demand for electricity. EIA projects  that demand for electricity will grow slowly over the next few years. This  means power companies may be less inclined to make, and state  electricity regulators may be less willing to approve of, investments in  electricity generating units that may not be needed as often. On the other  hand, if the economic recovery is more robust, there could be more  electricity demand than expected, which might increase the need for  additional generating capacity in some areas. Another factor that  contributes to uncertainty is the price of fuels. Natural gas prices have  decreased in recent years, and coal prices have increased, narrowing the  historical cost advantage of using coal to produce electricity in some parts  of the country. As a result of these changing prices, among other things,  the use of natural gas to produce electricity has increased and is  expected to continue to increase. For example, EIA recently projected  that the use of natural gas to produce electricity in 2012 could increase by  24 percent, and that, in turn, electricity generation from coal could decline  by 15 percent. However, some stakeholders we interviewed raised  concerns about the prospects for continued low natural gas prices, citing  the potential increased future use of natural gas for electricity or more  strict regulation of natural gas production that could affect the long-term  outlook for domestic natural gas production and prices.

Another factor that contributes to uncertainty is the increased focus on  renewable energy production and other potential future regulations. In  recent years, there have been federal and state efforts to encourage the  development of renewable energy sources—particularly wind and solar— to produce electricity. For example, 30 states have laws or regulations  requiring power companies to increasingly rely on renewable sources for  electricity. renewable sources increasing from 10 percent in 2010 to 16 percent of  total electricity generation by 2035, potentially diminishing the demand for  electricity from fossil fuels, including coal, in the future. Some  stakeholders we met with noted that there is uncertainty about future  environmental requirements, in particular those aimed at reducing carbon   Such future requirements  dioxide emissions to address climate change.

These states are: Arizona, California, Colorado, Connecticut, Delaware, Hawaii, Illinois,  Iowa, Kansas, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana,  Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio,  Oregon, Pennsylvania, Rhode Island, Texas, Washington, West Virginia, and Wisconsin. could affect the attractiveness of additional investments by power  companies in existing coal-fueled generating units because coal-fueled  units are more carbon intensive than other forms of generating electricity.  As we have previously reported, on average, coal-fueled units produced  twice as much carbon dioxide as natural gas units in 2010.

Power Companies Are Expected to Retrofit Many Generating Units, Retire Others, and Take Additional Actions

According to available information, power companies are projected to  retrofit many coal-fueled generating units with environmental controls and  retire some other units, as well as take additional actions to respond to  the four key EPA regulations.

Retrofit many coal-fueled generating units. All 12 of the studies we  reviewed suggest that power companies may retrofit many coal-fueled  generating units with new or upgraded controls to respond to the four  key regulations. EPA’s analyses and two other studies we reviewed  report national projections of how companies may reduce emissions  of air pollutants to meet the finalized MATS and CSAPR  requirements. Projections in these studies suggest that one-third to  three-quarters of all coal-fueled capacity could be retrofitted or  upgraded with some combination of controls, including the following:  (1) fabric filters or electrostatic precipitators to control particulate  matter; (2) dry sorbent injection or flue gas desulfurization units—also  known as scrubbers—to control SO and acid gas emissions; (3)  selective catalytic reduction or selective non-catalytic reduction units  to control NO; and (4) activated carbon injection units to reduce  mercury emissions. Appendix IV describes these controls, how they  operate, and the extent of their use among coal-fueled generating  units. Two of the studies we reviewed include estimates of how power  companies may respond to CCR, projecting that some companies  would convert power plants from wet ash handling to dry ash  handling, which uses conveyor belts or trucks to gather and transport  coal combustion residuals to storage sites, since wet ash  impoundments may effectively be phased out under the final CCR  regulation. These two studies projected that companies could  convert 96-98 and 158 power plants to dry ash handling  respectively. For power companies to respond to the proposed  316(b) regulation, EPA estimates that approximately 224 generating  units may install intake screens called modified traveling screens— screens or buckets that collect fish from the cooling intake water and  return them safely to the source water body—or reduce the facility’s  water intake velocity to meet impingement requirements. In addition,  two studies estimated how many power plants may install cooling  towers to meet the proposed 316(b) entrainment requirements,  projecting that 46 and 92-93 plants may do so. These projections  are uncertain since the proposed regulation gives permitting  authorities the responsibility to set entrainment requirements on a  case-by-case basis.would be installed at a coal-fueled power plant.

Actions Taken by Power Companies Will Likely Increase Electricity Prices and May Contribute to Reliability Challenges in Some Regions

Available information suggests the actions power companies take to  respond to the four key regulations will have costs, and some may be  challenging to complete by the regulations’ compliance deadlines. In  addition, these actions may have varied implications across the country—  increasing electricity prices in some regions and contributing to some  potential reliability challenges.

Estimated Costs of Power Companies’ Actions in Response to Four EPA Regulations

Two of the studies we reviewed reported national estimates of the total  costs of actions power companies may take in response to the four key  EPA regulations, projecting from $16 billion to $21 billion in additional  annual costs. EPA analyzed each regulation individually and projected  annual compliance costs of $10.2 billion for MATS, $853 million for  CSAPR, $600 million to $1.5 billion for CCR depending on which option is  finalized, and $397 million for 316(b). According to EPA reports, in  addition to operating and maintenance costs, a typical coal-fueled unit  with a capacity of 700 MW could incur costs from $287 million to $351  million to install a scrubber, from $116 million to $137 million to install a  selective catalytic reduction unit, and from $97 million to $114 million to  install a fabric filter. Other controls are less expensive, and a 700 MW  unit could incur $22 million to $43 million to install a dry sorbent injection  unit or $4 to $5 million for an activated carbon injection unit, according to  EPA reports.

Additional costs could be incurred to build or acquire new generating  capacity or to upgrade transmission systems due to unit retirements. For  example, MISO estimated that building new generating capacity in its  region to offset capacity lost from unit retirements could cost from $2  billion to $10 billion and that an additional $580 to $880 million in  transmission upgrades could be required to maintain reliability criteria  after potential unit retirements in net present value terms. MISO’s study is  the only one we identified that estimated potential transmission  investments needed to maintain reliability.

Some Actions May Be Challenging to Complete by Compliance Deadlines

Assessments by EPA and DOE suggest that much of the electricity  industry may be able to complete actions by the compliance deadlines. In  their assessments, EPA and DOE compared past coal-fueled generating  unit retrofits to the MATS compliance deadline. DOE found that,  assuming prompt action by regulators and generators, the timelines  associated with retrofits and new construction are generally comparable  to EPA’s regulatory deadlines. EPA reported that a reasonable,  moderately paced effort would result in the majority of needed retrofits  being installed by 2015 with the possibility of some retrofits needing up to  an additional year for completion. In addition, EPA’s analysis stated that  past experience may not reflect industry’s ability to deploy controls at a  faster pace in the future using overtime, additional off-site modularization  and prefabrication.

At the same time, power company representatives and other stakeholders  suggested that it might be challenging to complete retrofits or retirements  by the compliance deadline for MATS in some cases. In this regard, an  analysis by the Utility Air Regulatory Group, a voluntary group whose  members include power companies, found that about 30 percent of  projects to install fabric filters might be completed by the 2015 MATS  compliance deadline and almost 70 percent of projects might be  completed by the 2016 deadline, with the 1-year extension available from  permitting authorities. EPA's study of the final MATS regulation  indicates that fewer fabric filters may be needed than were assumed by  the Utility Air Regulatory Group, and the group's results suggest that it  may be possible to complete these by the 2016 deadline with the 1-year  extension. Similarly, actions to mitigate capacity loss and other  challenges due to generating unit retirements could take time as they  could involve building new generating units or upgrading transmission  systems. If these actions cannot be completed before compliance  deadlines, a reliability challenge could arise unless steps are taken to  keep generating units that are critical for the reliability of the electricity  system from retiring. There have been examples of efforts to conduct  transmission upgrades to address reliability challenges that have taken  longer than the 4 years that may be available to meet the MATS  compliance deadline assuming a 1-year extension. For example,  transmission upgrades were necessary to allow several generating units  with total capacity of 790 MW to retire at the Benning Road and Buzzard  Point power plants on the Potomac Electric Power Company system,  which serves 788,000 customers in Maryland and the District of  Columbia. In 2007, the plants’ owner notified the system planner of its  desire to retire the units by mid-2012. The needed transmission  upgrades, including new transformers and circuits, are expected to be  completed in mid-2012.

Retrofits of generating units, transmission system upgrades, and the  construction of new generating units can be major engineering  undertakings, and several power company representatives and other  stakeholders we interviewed said that completing some of these  undertakings by compliance deadlines may be challenging in some  cases. Stakeholders expressing concerns highlighted the following three  reasons meeting these deadlines could be challenging, particularly for  MATS compliance:

Regulatory approvals can take time. Retrofits, transmission line  upgrades, and construction of new generating units will require  various state and local regulatory approvals, which may include  construction permits and modifications of air pollution permits, which  can extend the completion time of such projects. In traditionally  regulated markets, power companies that decide to undertake a  retrofit or new construction may also need to obtain a review by the  state utility commission in order to include associated costs in  electricity rates. Some of these approvals can be pursued  concurrently with or be obtained after design, construction, and start- up, but some may extend completion times.

Site-specific concerns for retrofits. In addition, some of the power  company representatives we interviewed told us that power plants  may have site-specific physical constraints that can slow completion  of work. For example, according to representatives at one company, it  took the company about 5 years to install fabric filters on four units at  one plant, in part because the site did not have space to place the  needed controls. The fabric filter for one of the units had to be  constructed 1,200 feet away and connected via ductwork. Figure 6  illustrates another power plant with site-specific concerns, constrained  by a river on one side and a highway and mountain on the other.  Officials from the power company owning this plant told us that they  generally construct a separate new stack for retrofitted scrubbers, but  this was not possible due to space constraints at this site. Instead, the  power company is installing ductwork from the scrubber through the  cooling tower in order to use the cooling tower as a stack.

Supply chain concerns. Some power company representatives and  other stakeholders stated that, because of the large number of  potential retrofits, they had concerns about the availability of specific  skilled laborers or equipment needed to install some controls. The  installation of some controls could entail significant retrofit efforts  industry-wide. For example, according to EPA, companies could  install fabric filters on an additional 102,000 MW of coal-fueled  capacity in response to MATS. This is almost double the coal-fueled  capacity that currently has fabric filters. The simultaneous installation  of air pollution controls has strained supply chains in the past. For  example, EPA stated that, from 2007 to 2008, when a significant  number of power plants installed scrubbers, delays as long as 18  months occurred for plants to obtain such key engineered equipment  as large pumps, motors, and chimneys that were needed. (See app.  IV for additional information on the controls installed on coal-fueled  units.) Some other stakeholders have said that there are sufficient  resources available and did not identify concerns related to supply  chain issues. EPA has stated that the controls needed to meet  CSAPR and MATS are much simpler and will take significantly less  time to plan, design, install, and commission than the controls that  caused strains in the past.

Impacts Are Expected to Vary Across the Country

The actions power companies take to respond to the four EPA regulations  are expected to affect some parts of the country less than others. First,  some areas of the country, such as California, Washington, Oregon, and  Maine, have little coal-fueled generation and, therefore, are expected to  see little impact. In addition, CSAPR would cover 28 states in the eastern  half of the United States, so generating units in the remaining states  would not be affected. Second, power companies in certain areas may  have already installed some of the needed controls on their coal-fueled  units for a variety of reasons. For example, at least 18 states have  enacted laws or regulations to limit mercury emissions from electricity  generation. To satisfy these state requirements, power companies with  coal-fueled generating units in these states may have already installed, or  be planning to install, controls that are also capable of meeting MATS  limits. These states may not see many additional changes in their  electricity systems. In addition, some regions have coal-fueled generating  units that were built more recently, and such newer units, as we reported  in April 2012, are more likely to have installed some controls that could be  helpful in meeting MATS and CSAPR requirements.areas, including the Midwest, Mid-Atlantic, and South, have higher  concentrations of coal-fueled generating units that do not have control  equipment needed to respond to the four key regulations. These areas  are more likely to be affected by the key EPA regulations.

Actions Would Likely Increase Electricity Prices in Some Regions

The actions power companies may take in response to the four key EPA  regulations would likely increase electricity prices in some regions. Of the  12 studies we reviewed, EPA and three other entities––Resources for the  Future (RFF), NERA Economic Consulting, and MISO––conducted  studies that project price impacts, but their results are not directly  comparable because they considered different sets of the four  regulations, report results differently, and examined different  configurations of states in their regional analysis. EPA’s analyses suggest  that MATS, by itself, may increase average retail electricity prices in the  contiguous United States by 3 percent in 2015 and 2 percent in 2020 and  have the most significant potential price impact of the four regulations.  EPA estimated that the potential impact of MATS on average retail  electricity prices in 13 regions could range from about a 1 percent  increase in a region covering most of California to about a 6 percent  increase in a region covering Kansas, Oklahoma, and parts of New  Mexico, Texas, Louisiana, Arkansas, and Missouri. Table 2 summarizes  the results of EPA’s studies.number of other factors, including changing prices of fuels and demand  for electricity. According to EPA officials, the projected price increases  associated with CSAPR and MATS are within the historical range of price  fluctuations, and projected future prices overall may be below historic  electricity prices. EPA officials also said that the regions of the country  most likely to experience larger price increases have historically had  lower than average prices and that they project that postimplementation  prices in these regions will remain below the national average.

Electricity prices are influenced by a   Narrow reserve margins in Texas and New  A few more detailed studies that examined local reliability and some  stakeholders we interviewed identified the potential for local reliability  challenges associated with the four key regulations. Furthermore,  representatives from some power companies, RTOs, and other  stakeholders told us that the combination of retrofits and retirements in an  area could raise system security challenges, for example, if they affect a  generating unit needed at a particular location to maintain the electricity  system’s voltage or to perform other highly technical services to ensure  the availability of electricity. Retirements and retrofits could contribute to  such concerns if generating units have not been able to retrofit on time or  because efforts to mitigate reliability effects are not completed in time.  According to EPA documents and some stakeholders we interviewed,  there are expected to be few such situations, and existing tools should be  sufficient to address issues that do arise. Figure 7 below shows how  planned retrofits and retirements through 2020 are distributed nationwide  and how these are concentrated in certain areas.

Specifically, available information and stakeholders identified three  potential reliability challenges that could occur at a local level. (For such  situations, regulatory or other tools may provide flexibility for resolving  challenges. These are discussed in the following section.)

Retrofits. Two aspects of retrofits can cause potential reliability  challenges. First, in certain cases, generating units will need to be  temporarily shut down to connect new controls, and some  stakeholders said that scheduling these shutdowns while maintaining  reliability could be challenging in certain areas. According to DOE,  shutdowns for the types of controls that may be undertaken in  response to MATS and CSAPR usually take less than 8 weeks. In  addition, these shutdowns can often be scheduled during regular  maintenance periods, and therefore may not require units to be shut  down for additional time. More time may be needed for some units,  however, because of site specific conditions—such as when a single  control device must be connected to multiple generating units—or  because installation involves the types of controls that take longer to  connect. For example, connecting activated carbon or dry sorbent  injection units may require less than a 1-week shutdown. Installing  scrubbers, which are more complex, typically requires a 3- to 8-week  shutdown, and these installations can sometimes take longer  according to information presented by DOE. Scheduling a large  number of these longer shutdowns may pose challenges. For  example, one system planner told us that companies typically try to  schedule such shutdowns during periods of normally low demand,  such as the spring and fall, but it may be difficult to schedule all of  these longer shutdowns during those periods between now and the  compliance date for MATS. Second, if power companies cannot install  controls in time to respond to MATS and CSAPR regulations, they  may have to shut some units down until such installations are  completed, also potentially posing reliability challenges. EPA officials  said that large numbers of air pollution controls were installed in  response to past regulatory requirements without raising major  reliability issues. However, NERC and two of the RTOs we  interviewed have expressed concerns about having sufficient  generating capacity as companies undertake retrofits that require  short-term shutdowns.

Retirements. It is not certain what portion of the 2 to 12 percent of  coal-fueled generating units expected to retire could cause reliability  challenges that would need to be addressed. Several stakeholders  said it could be difficult to resolve all potential reliability challenges  that may arise because of retirements before the 3-year MATS  compliance deadline established by statute. There have been  examples in the past of efforts to resolve reliability issues as a result  of retirements that have taken multiple years to resolve, and two of  the RTOs we spoke with have identified similar challenges going  forward. For example, PJM Interconnection (PJM), an RTO system  planner in the Mid-Atlantic and Midwest, received 116 requests from  power companies to retire units, as of May 30, 2012—representing  16,184 MW of capacity and almost 9 percent of capacity under PJM’s  authority. PJM has identified reliability concerns with 101 of these  retirement requests because they may cause violations of reliability  standards. PJM has identified solutions to these potential violations,  including transmission upgrades and operational changes, and stated  that it expects the resolution of its reliability concerns with 16 of these  retirements to take past April 2016—the MATS compliance deadline  for units with a 1-year extension. Similarly, as of May 3, 2012, MISO  has identified reliability challenges with 8 of the 62 unit retirement  notifications it has received and completed evaluations on. MISO  expects 5 of these to take until 2018 to resolve.

Increasing reliance on natural gas. Several stakeholders said that  increasing dependence on natural gas to produce electricity could  pose potential reliability challenges because there could be  interruptions in the delivery of natural gas to generating units. In  particular, one stakeholder said that there can be other natural gas  users on pipelines, such as homeowners in regions of the country  where natural gas is used as a home heating fuel, who may also  consume natural gas during periods of peak demand. In these areas,  constructing pipelines to improve the supply of natural gas to existing  or new natural gas-fueled generating units could take time because of  a range of financial and regulatory steps that must be taken. Without  such upgrades, there may be inadequate natural gas supply in certain  locations where it is needed for electricity generation. While pipeline  capacity is being expanded in some regions of the country to  accommodate rising demand, several stakeholders raised concerns  about gas-electric coordination in the industry. To better understand  and prepare for these challenges, MISO recently completed a study  on the availability of natural gas pipeline infrastructure to support  increased use of natural gas-fueled capacity. The study found that  some of the region’s pipelines that deliver natural gas to power plants  may be close to capacity and that further investments in pipeline  capacity and additional natural gas storage may be needed to ensure  the delivery of reliable natural gas supplies.

Existing Tools Could Mitigate Many Adverse Implications, but Agencies Do Not Have a Formal Process to Monitor Industry Progress Toward Compliance

Various tools available to industry and regulators could help mitigate  potential adverse electricity market implications, including some price  increases, associated with requirements in the four key regulations.  Various tools could also address many, but not all, potential reliability  challenges associated with these regulations. In addition, FERC, DOE,  and EPA have begun taking steps to monitor industry’s progress in  responding to the regulations but have not established a formal,  documented process for jointly and routinely doing such monitoring, and  FERC has not taken steps to proactively assess RTO rules in the context  of the EPA regulations.

Available Tools May Help Mitigate Some, but Not All, Price Increases

Various tools available to industry and regulators could help mitigate  some, but not all, potential increases in the prices consumers pay for  electricity. In traditionally regulated markets, in order to determine  whether to allow power companies to recover the costs of responding to  the regulations, public utility commissions will hold proceedings to review  whether power companies’ investments in response to the four key EPA  regulations are prudent. These proceedings could involve consideration  of whether a power company’s compliance strategy—whether to invest in  controls, modify a unit to produce electricity using a different fuel source,  retire a unit, or build a new unit—is defensible. They could also include a  review of the actual costs involved in installing controls. Once approved  by the regulator, ratepayers in these markets primarily bear the risk  associated with actions to comply with the regulations. State public utility  commissions may also review longer-term resource plans developed by  power companies to identify when new capacity is needed to  accommodate unit retirements and, if appropriate, approve power  companies’ proposed approaches for obtaining that capacity—building  new units, entering into long-term power contracts, or other steps. For  example, in 2012, the Georgia Public Service Commission reached a  decision in its proceedings to review Georgia Power Company’s plans to  retire certain generating units and purchase power from other sources to  address, among other things, state pollution regulations and MATS. In  addition to its other rulings, the Georgia commission approved three of  the four power purchase agreements, indicating that such a decision  represented the best balance of increased cost to consumers with the  benefits of having additional capacity.

In restructured markets, where the prices consumers pay for electricity  are influenced by prices set in competitive, organized wholesale markets,  the competitive nature of these markets provides an incentive for power  companies to ensure that their investment decisions are cost-effective. In  these markets, investors in the power company bear the risk associated  with these decisions—the installation of any controls that turns out to  have been unnecessary or too costly may not yield the additional revenue  needed to pay for the investment. In addition, to ensure these markets  remain competitive and that prices reflect the cost of producing electricity,  FERC officials told us that RTOs and FERC have processes in place to  identify, investigate, and prosecute manipulative behavior in wholesale  electricity markets, as well as to ensure that prices are set in well- functioning markets representing the interplay of supply and demand.  Several stakeholders we spoke with said these processes should be  effective at keeping power companies from using actions they may take in  response to the EPA regulations as an opportunity to manipulate the  electricity markets.

However, these tools in traditionally regulated and restructured markets  do not limit power companies from passing on to consumers any  legitimate costs they incur in responding to the EPA regulations, such as  the costs of installing controls, procuring CSAPR allowances, constructing  transmission lines to address reliability challenges, and acquiring power  from other sources to compensate for retiring generating units. Two of the  state public utility commission representatives we spoke with from  traditionally regulated markets said it would be unlikely for a public utility  commission to deny cost recovery for prudent investments needed to  respond to these EPA regulations. In restructured markets, power  companies will attempt to recover the costs they incurred in responding to  the regulations through the electricity markets. To the extent that price  increases are the result of prudent steps in response to the EPA  regulations rather than market manipulation, federal or state regulators  may have little authority to mitigate them.

EPA has designed the regulations with some provisions that provide  flexibility and allow power companies to minimize the costs of responding  to them, which may reduce consumer electricity price increases. For  example, by making CSAPR allowances tradable rather than requiring all  generating units to individually meet a particular emissions threshold,  EPA may enable power companies to achieve overall emissions limits at  a lower cost. Additionally, EPA requested public comment on several  regulatory provisions in the proposed CCR regulation which, according to  EPA officials, could help lower industry compliance costs and reduce  price increases.

In addition, some tools could lower demand for electricity, which may  offset potential price increases. For example, some states have provided  incentives for consumers to purchase more energy efficient household  appliances as part of an effort to avoid constructing additional generating  units. Furthermore, electricity pricing and other programs can encourage  customers to adjust their usage in response to changes in prices or  market conditions, which can affect reliability. These programs are  collectively referred to as “demand-response” programs, and two types— ”market-based pricing” and “reliability-driven”—are in use. Market-based  pricing programs enable customers to adjust their use of electricity in  response to changing prices. Reliability-driven programs, on the other  hand, enable system operators to request that customers reduce  electricity use when needed, such as if hot weather or system  malfunctions mean that demand will probably exceed supply and cause a  blackout. In August 2004, we reported that demand-response programs  promote greater efficiency in supplying electricity by postponing the need  to construct new generating units and reducing the need to use the  generating units that are the most costly to operate. We recommended  that FERC consider the presence or absence of demand response when  making key decisions about electricity markets, including whether to allow  some buyers to participate in wholesale markets. In response to our  recommendation, FERC has taken steps to facilitate broader use of  demand-response programs among RTOs.

Available Tools Could Address Many, but Not All, Reliability Challenges

Tools available to industry and regulators may also help address many,  but not all, potential reliability challenges. For example, planning, market,  and operational tools used by system planners and operators to ensure  the availability of adequate transmission and generation will help address  many potential reliability challenges associated with these regulations.  System planners and operators, whether RTOs or individual power  companies, manage the electricity system in accordance with NERC  reliability standards. With respect to transmission, system planners  compare the long-term demand for electricity at various points throughout  the system to the location, capacity, and operating limits of generation  and transmission resources. These activities require timely information  on, among other things, planned retirements and new additions. EPA  provided one mechanism through which system planners may receive  this information in a more timely way when it instructed power companies  seeking Clean Air Act administrative orders—orders to give units up to an  additional year to come into compliance with MATS—to provide  compliance plans to system planners. In addition, some RTOs have  begun requesting that power companies in their regions voluntarily  provide early information on their plans to respond to the regulations,  including planned retirements, retrofits, and operational changes. With  respect to generation, system planner activities vary, with some areas of  the country planning their future investment in generation and others  using market-based approaches to encourage the development of new  generation. System operators take more immediate actions to ensure the  grid operates in conformance with NERC reliability standards, such as  directing when to bring additional generation online to meet demand or  improve system operating conditions. System planners and operators  must manage changes that power companies make to respond to the  EPA regulations—retiring generating units, changing operating  schedules, or scheduling shutdowns to install controls—in a way that  does not violate NERC’s reliability standards.  For example, system  planners must maintain adequate contingency reserves—such as  additional available generation or electricity consumers willing to lower  their demand for electricity—to address any unexpected operational  problems that arise, even when some electricity generating units retire or  are out of service to install controls. Broader initiatives in the electric  power industry, such as activities to promote demand-response and  energy efficiency, may also help mitigate reliability challenges.

Although these planning, market, and operational tools could address  many potential reliability challenges, challenges may still arise if  generating units needed for reliability are not in compliance with the EPA  regulations by the deadlines. For example, local reliability challenges  could occur if generating units that need to operate in a local area to  ensure resource adequacy or system security do not meet these  regulations’ compliance deadlines––either because they have not been  able to retrofit on time or because system planners have not yet  completed efforts to mitigate the reliability effects of the units’ planned  retirement. However, according to EPA officials and documentation, most  units should be able to complete steps to respond to the regulations prior  to their deadlines. Nonetheless, some stakeholders remain concerned  and told us that the loss of reliability-critical units that cannot comply by  the deadlines could have an adverse impact on reliability.

These administrative orders are authorized by section 113(a) of the Clean Air Act and,  by statute, cannot last for longer than a year or be renewed. year. According to EPA’s MATS enforcement memo, EPA does not  intend to seek civil penalties for violations of the MATS regulation that  occur as a result of operation in conformance with these  administrative orders. Power companies that intend to seek these  orders must, among other things, notify system planners by April 16,  2013, of their MATS compliance plans, which EPA expects to help the  system planners better manage possible reliability challenges.  However, EPA officials told us that such notifications are not required  if a power company does not intend to seek additional time to  respond, such as if it plans to retire its generating units. Furthermore,  some stakeholders have raised concerns that administrative orders do  not shield power companies from private parties suing them for  violating the MATS regulation.address situations in which units need more than 5 years to comply.  EPA officials told us that, if generating units need additional time to  respond, EPA will make case-by-case decisions about how to  proceed by using, for example, the consent decree process described  below.

These consent decrees are authorized by section 113(b) of the Clean Air Act. develop it. In addition, according to EPA officials, power companies  must be willing to enter into consent decrees. However, in the case of  a retiring generating unit, it may be the system planner, rather than  the power company, that wants to keep the unit operating. As a result,  a power company that wants to retire a reliability-critical generating  unit may have little incentive to enter into a consent decree,  particularly if it means paying a penalty to do so.

Reliability must-run agreements. Reliability must-run agreements— which provide cost-based payments to the owners of reliability-critical  generating units to cover the cost of operating these units past when  their owners were planning to retire them—are another possible tool  for addressing some reliability challenges. These agreements have  been used in the past to address occasional retirements of individual  generating units due to changing economic conditions, such as when  operating a unit became unprofitable. For example, a reliability must- run agreement was used to keep Hudson Unit 1, a 383 MW unit in  New Jersey, operational for reliability reasons for 7 years after the  Public Service Enterprise Group, the power company that owns the  unit, had requested to retire it. A reliability must-run agreement was  needed for so long, in part, because of delays in the construction of a  transmission line that was being developed to address potential  reliability violations that could occur without the new line. However,  these agreements may not be an option for responding to all types of  reliability challenges that could arise when power companies seek to  retire reliability-critical generating units in response to the four key  regulations. According to representatives from some RTOs we spoke  to, reliability must-run agreements have historically been used to  reimburse power companies for their operating expenses rather than  major capital and other expenditures, such as the installation of  controls to reduce pollution, or financial penalties for violating  environmental laws and regulations. As such, in situations where a  power company plans to retire a generating unit, reliability must-run  agreements may be useful if an administrative order or consent  decree can be obtained. If not, reliability must-run agreements may be  less applicable because those units would either have to install  controls in order to comply or risk financial penalties for  noncompliance.

DOE emergency authority. DOE’s authority under section 202(c) of  the Federal Power Act to order a power company to generate  electricity in certain emergencies is another tool through which  reliability challenges resulting from actions to comply with the four  regulations may be addressed. For example, DOE could use this  authority to require a retiring electricity generating unit that emits more  mercury than allowed by MATS to continue to operate after the MATS  compliance deadline if the unit was needed to respond to an  emergency because of an electric shortage. However, DOE officials  told us that they expect to use their section 202(c) authority to  address reliability concerns associated with the EPA regulations rarely  and as a tool of last resort. Further, in some circumstances, this  authority may not provide for timely resolution of potential reliability  challenges associated with the four EPA regulations. DOE has used  its section 202(c) authority six times in the past, and officials told us  that, in most instances, DOE has been able to issue section 202(c)  orders quickly.where it is less obvious whether there is a reliability emergency, it  could take time for officials to analyze whether the requirements for an  order are met and issue the order.

However, DOE officials explained that, in situations  In addition, although DOE may coordinate with EPA and state  environmental regulators to ensure the section 202(c) order that is  issued does not result in a violation of environmental requirements,  some power company representatives expressed concern that  operating under a section 202(c) order could still result in a potential  conflict between DOE’s order and environmental laws and  regulations. This could occur if DOE issued a section 202(c) order  before agreement could be reached with EPA and state  environmental regulators on how to operate the unit to adequately  respond to the emergency and comply with applicable environmental  laws and regulations.told us that, in these situations, it is unclear whether the power  company would (1) refuse to generate electricity and risk electricity  reliability or (2) operate in violation of the environmental laws and  regulations and risk enforcement action and legal liability. A legal  representative at one power company we spoke with explained that  he could not advise company officials to operate a unit in violation of  the Clean Air Act without additional legal protection. Representatives  from another power company said that power companies in such a  situation may defer to the courts—a potentially time-intensive  solution—to avoid legal liability and determine what course of action  they should take. Moreover, power companies may have to negotiate  with, or seek approval from, multiple additional parties, including the  relevant RTO and FERC, for an agreement outlining the payment  terms for the unit’s operation under the section 202(c) order, as well  as with EPA and state environmental authorities to avoid financial  penalties if operation results in violation of environmental laws and  regulations. Getting these agreements in order can also be time- consuming which, if the process is not started well in advance, may  delay steps to address reliability. EPA staff commented that the  agency will be closely tracking cases where extensions and orders  are used.

Representatives from two power companies

Clean Air Act section 112 presidential exemption authority. The broad  authority provided to the President to exempt power companies from  complying with MATS is a potential tool to avoid reliability challenges,  but this authority has never been used, and uncertainties exist as to  how this tool would apply to reliability challenges that arise under  MATS. Section 112(i)(4) of the Clean Air Act authorizes the President  to exempt any generating unit from compliance with MATS for a  period of not more than 2 years under certain circumstances.

Specifically, the President must make two determinations to use this  authority: (1) that the technology to implement the regulation is not  available and (2) that the exemption is in the national security  interests of the United States. As of May 2012, this authority has  never been used, and there is uncertainty about whether these  conditions could be met. For example, as to the first determination,  EPA established emissions standards for mercury and other  pollutants that can be met with technology that has been available for  a significant time. However, according to EPA staff, EPA’s rulemaking  was not intended to and did not consider the interpretation of the term  ‘available’ as used in the presidential exemption provision.  Furthermore, regarding the second determination, EPA staff explained  that the record supporting EPA’s rulemaking includes some  information that others might consider relevant in making any such  determination. EPA officials also noted, however, that section  112(i)(4) authorizes the President, not EPA, to act. Regarding these  determinations, according to one stakeholder, it would be implausible  to claim that technology to comply with MATS is not available, and  there is not currently evidence of a sufficient threat to national  security. Another stakeholder, however, has argued that the statute is  sufficiently broad to allow the exemption authority to be used in some  situations when a power company does not have the physical ability  to obtain, purchase, and install technology by the deadlines and that  the true extent of reliability challenges' threat to national security  interests cannot be fully known until specific reliability studies are  completed based on specific compliance plan proposals. Several  stakeholders we spoke to during this review indicated that the  presidential exemption authority can be used, though two said the  statute establishes a high threshold that must be met.

In addition to these six tools, some provisions in two of the regulations— CSAPR and 316(b)—help address electric reliability. For example,  CSAPR allows power companies to run existing controls more often,  install additional controls, or acquire allowances by purchasing them from  another source or using allowances saved from prior years. According to  EPA officials, this flexibility can help power companies plan and manage  their operations in a manner that ensures system reliability. With respect  to 316(b), as indicated in the preamble to the proposed regulation,  permitting authorities have flexibility to tailor compliance timelines to  enable installation without negatively impacting the reliability of electric  supply.

Agencies Have Begun Taking Steps to Monitor Industry’s Progress but Have Not Documented Their Process, and FERC Has Not Proactively Reviewed RTO Rules

FERC, DOE, and EPA have begun taking steps to monitor industry’s  progress in responding to the regulations but have not established a  formal, documented process for joint and routine monitoring, and FERC  has not taken steps to proactively assess RTO rules in the context of the  regulations. FERC, DOE, and EPA officials said they have taken initial  steps to understand the status of industry’s plans to respond to the  regulations, and officials from each agency told us they have periodically  met with affected stakeholders—for example, power companies, state  public utility commissions, and all of the RTOs, among others—to discuss  the regulations’ impact and the status of industry compliance. For  example, staff from all three entities said they have had multiple  conference calls with RTOs in areas affected by the regulations. In  addition, FERC hosted a technical conference in 2011 to discuss policy  issues related to the EPA regulations with industry stakeholders, and  FERC and state public utility regulators have established a forum to  explore reliability challenges related to the EPA regulations.Furthermore, according to EPA staff, the agency had multiple meetings  with all of the major utility trade associations, as well as a number of large  power companies with substantial coal-fueled generating capacity, to  discuss compliance plans and issues that are emerging. However, each  agency’s efforts are varied in scale and scope, and none of the agencies  has developed a formal, documented process for routinely monitoring  industry progress, including goals for any monitoring activities, data to be  collected and analyzed, and how the agencies will use this information.  Officials from FERC and DOE told us they had not formalized their  processes for monitoring industry’s progress since power companies  were in the process of finalizing their approach for responding to the  regulations.

As discussed, actions power companies take in response to the four  regulations may present potential reliability challenges, or risks. In a  December 2005 report on risk management, we reported that monitoring  is essential in ensuring that a risk management approach is current and  relevant. Without a formal, documented process that the three agencies  have agreed on for monitoring industry’s progress toward meeting the  compliance deadlines, it is uncertain how comprehensive the agencies’  monitoring efforts will be and whether they will adequately address such  specific issues as the status of required regulatory approvals, the  availability of key materials and skilled workers, the likelihood of potential  reliability challenges, and the adequacy of existing tools for addressing  these challenges. Without a formal, documented process for monitoring,  it is also uncertain whether the agencies’ future monitoring activities will  be sufficiently comprehensive to alert them in advance if a larger than  expected number of reliability challenges arise so they can assess  whether internal agency resources are available to carry out their  responsibilities. For example, if there is a larger than expected number of  local reliability challenges, FERC may be less able to effectively and  quickly manage reviewing (1) applications for cost recovery for  transmission investments, (2) the reliability impacts of electricity  generating units whose owners seek an administrative order from EPA for  compliance with MATS, (3) reliability must-run agreements outlining the  payment terms for the operation of a unit that would otherwise retire, and  (4) whether steps should be taken to require RTOs or market participants  to secure additional demand-response resources.

Furthermore, these three agencies have informally collaborated about the  EPA regulations, but they have not developed a formal, documented  process for coordinating their monitoring efforts. Officials from all three  responsible agencies said they have held periodic discussions with  officials from the other agencies. This informal collaboration also involved  participation in the FERC technical conference on the EPA regulations  and joint agency participation at meetings with industry stakeholders.  EPA officials told us the agencies have agreed to work together to  monitor the progress of industry’s compliance with the regulations in the  future. However, these agencies have not documented their process for  coordination, including the expected frequency of contact with each other  and industry, key agency responsibilities, and how they will share  information. We have previously reported that by using informal  coordination mechanisms, agencies may rely on relationships with  individual officials, which could end once personnel move to their next  assignments. We reported that agencies can strengthen their  commitment to work collaboratively by articulating their roles and  responsibilities in formal documents—such as memorandums of  understanding or interagency planning documents—to facilitate decision  making. These documents can clarify which agencies will be responsible  for particular activities and how they will organize their individual and joint  efforts. Without more formal coordination mechanisms, any assessment  of whether tools are sufficient to mitigate potential reliability challenges  may not fully leverage the perspective of all three agencies, each of which  has a unique area of expertise and ability to perform different analysis.  Each of the three agencies may have knowledge of whether particular  tools are useful for addressing actual reliability challenges, and DOE and  FERC may be able to provide insight into the magnitude and urgency of  such challenges.

Moreover, according to agency officials, the agencies do not have a  formal, documented process for how they will provide information from  their monitoring efforts to Congress. Without information on whether  existing tools are sufficiently timely, relevant, and effective for addressing  any adverse implications that arise, Congress may not be sufficiently  informed about whether additional statutory authority is needed. Through  multiple hearings and an information request to FERC, members of  Congress have already sought additional information on these issues.  Legislation has also been introduced to, among other things, extend the  compliance dates for MATS and CSAPR, to prohibit or invalidate one or  more of the regulations, and establish that compliance with a section  202(c) order cannot be considered a violation of any environmental law or  regulation. Without information such as what could be provided through  EPA, FERC, and DOE’s joint monitoring efforts, Congress will be less  informed when it deliberates these bills about the extent to which actual  reliability concerns arise and whether new statutes are needed to address  them.

Furthermore, FERC has not taken steps to proactively assess whether  RTO market rules and similar rules at non-RTO system planners will be  adequate to ensure timely, cost-effective mitigation of the potential  reliability challenges associated with the multiple generating unit  retirements and outages that may occur over a short period due to the  EPA regulations and other factors. These rules govern such things as  how these entities schedule temporary shutdowns for retrofits, receive  notifications from power companies regarding retirements of generating  units, and address potential reliability challenges, including how  transmission upgrades and demand response are considered and  pursued. These rules affect how cost-effectively reliability challenges are  managed. Table 3 shows examples of RTOs that have begun reviewing  their rules related to electricity transmission, markets, and other areas  and are considering whether changes are needed in light of the EPA  regulations and other industry factors. Changes under consideration  relate to scheduling outages, unit retirements, and planning for  transmission needs. Many are being considered with the goal of avoiding  unnecessary costs or reliability problems. For example, under current  market rules in the MISO region, power company retirement requests are  binding, meaning once a power company has submitted a request to  retire, it cannot change its mind. MISO stakeholders are discussing  whether changes need to be made to market rules to allow power  companies to submit nonbinding requests for unit retirements, so that  MISO can provide these companies with information on the reliability  impacts of their proposed retirements prior to these companies making a  final decision about whether to retire. According to MISO officials, if a  power company received this information prior to making a retirement  decision, the company might be able to make more cost-effective choices  by comparing the cost of steps to address reliability concerns associated  with a potential retirement to the cost of complying with the regulations by  installing environmental controls.

FERC officials told us that initial discussions with the RTOs—such as  through the FERC technical conference—indicated that current market  rules are adequate and that FERC will review any proposed changes to  market rules that they receive from RTOs to ensure that the rules  continue to promote just and reasonable rates and, where relevant,  address reliability issues. However, the commission does not have plans  to proactively assess the adequacy of any rules unless RTOs propose  specific changes. Furthermore, FERC officials said the commission does  not plan to evaluate whether changes proposed by one RTO may also be  useful at others. FERC officials said they have also not assessed the  rules of non-RTO system planners because FERC has more limited  authority over non-RTO rules. However, FERC officials acknowledged  that they have the authority to proactively request that RTOs make  changes to rules if FERC believes a rule change is warranted. Under the  current approach—wherein individual RTOs consider potential changes  and request approval from FERC—FERC risks taking a piecemeal  approach to oversight and may miss opportunities to encourage  development of market rules in all regions that are adequately designed  to promote just and reasonable rates in the context of the industry’s  transition.

The four key EPA regulations—two finalized and two proposed—would  reduce adverse health or environmental impacts associated with coal- fueled electricity generating units, potentially avoiding thousands of  premature deaths each year. Aspects of these regulations remain  uncertain, but they, along with other industry trends such as the aging of  coal-fueled generating units and lower prices for natural gas, are  expected to contribute to significant changes in electricity systems in  some parts of the United States in the near future. These potential  changes, which include retrofitting many coal-fueled units and retiring  more coal-fueled capacity than has been retired over the past 22 years,  have implications for electricity prices and reliability. FERC, DOE, and  EPA each have key responsibilities concerning the electricity industry and  all three agencies have taken steps to address potential adverse  implications associated with these regulations.

Existing tools provide a foundation for mitigating many of the price and  reliability implications of actions power companies may take in response  to the regulations. However, these tools may not fully address all potential  adverse implications in some regions, for example, some reliability  challenges that arise after the compliance deadlines. Knowledge of the  severity and extent to which challenges arise will be key to understanding  whether existing tools are adequate or additional tools are needed.  FERC, DOE, and EPA have taken important first steps to coordinate with  RTOs, other system planners, and state regulators, among others, to  better understand these issues. However, without a formal, documented  process that the three agencies have agreed upon for jointly, routinely  monitoring industry’s progress, it is uncertain whether their activities will  be sufficiently comprehensive and fully leverage their unique areas of  expertise. FERC, DOE, and EPA can build on their initial monitoring  efforts by documenting their process for monitoring, including the  expected frequency of their contact, and how they will organize their  efforts and share information. Moreover, as shown by multiple hearings  and the introduction of legislation that would affect some or all of the  regulations, there has been congressional interest in the potential  reliability and price implications of these regulations. Information from a  coordinated monitoring effort could help inform these ongoing  deliberations and make clear whether additional statutory authority is  needed to cost-effectively address any reliability challenges that actually  arise.

In addition, rules at system planners, including RTO market rules and, in  some cases, similar rules at non-RTO system planners, govern such  details as how these entities schedule temporary shutdowns for retrofits;  receive notification from power companies regarding retirements of  generating units; and address potential reliability challenges, including  how transmission upgrades and demand-response are considered and  pursued. These rules matter greatly in terms of whether potential  reliability challenges are managed as cost-effectively as possible. FERC  has not proactively evaluated whether RTO rules will be adequate to  ensure timely, cost-effective mitigation of potential reliability challenges  associated with multiple generating unit retirements and shutdowns,  which may occur over a short period in light of the EPA regulations. As a  result, FERC may miss opportunities to encourage development of rules  in all regions that are adequately designed to promote just and  reasonable rates in the context of the industry’s transition.

We are making the following two recommendations:

To further strengthen agency efforts to understand whether existing  tools are adequate, or additional tools are needed, we recommend  that the Chairman of FERC, the Secretary of Energy, and the  Administrator of the EPA develop and document a formal, joint  process consistent with each agencies’ respective statutory  authorities to monitor industry’s progress in responding to the EPA  regulations until at least 2017. Each agency, to the extent practical,  should leverage resources and share the results of its efforts with the  other agencies. The agencies should consider providing Congress  with the results of their monitoring efforts, including whether additional  statutory authority is needed to address any potential adverse  implications.

To ensure that RTO market rules and, to the extent practical, similar  rules at non-RTO system planners promote timely, cost-effective  mitigation of potential reliability challenges associated with the EPA  regulations reviewed in this report, we recommend that the Chairman  of FERC assess the adequacy of existing rules for this purpose. In  particular, this assessment should cover rules related to scheduling  retrofits, retirement notification, and whether more can be done to  facilitate demand response. If the FERC Chairman determines that  these rules are not adequate, FERC should consider requesting that  these entities make changes where appropriate.

We provided a draft of this report to FERC, DOE, and EPA for comment.  In written comments, which are reproduced in appendixes V through VII,  DOE and EPA agreed with the recommendation directed to them, and  FERC disagreed with both recommendations directed to it.

Regarding our first recommendation that FERC, DOE, and EPA develop  and document a formal process to monitor industry's progress in  responding to the EPA regulations, DOE and EPA generally agreed.  FERC disagreed with the recommendation, stating that we did not take  into account a number of actions FERC has taken, including publicly  committing to work closely with industry, states, and other agencies to  address issues that arise. FERC cited several examples of the actions it  has taken, and we made some clarifying changes and, in one case,  added language about an example that we had not previously included in  the report. FERC also stated that it had taken further steps to implement  our recommendation after seeing our draft report. We agree that FERC  has taken positive steps, and we are encouraged that FERC has begun  to implement our recommendations. However, we do not believe these  actions adequately represent the type of formal, documented process  needed for EPA, DOE, and FERC to monitor industry's progress in  responding to the regulations. FERC also said that, as an independent  agency, it cannot dictate the sharing of information with and by other  parts of the government. We acknowledge there may be limits on the  extent to which the three agencies can collaborate and clarified our  recommendation accordingly. All three agencies noted that they are  working to establish a more formalized approach to continued  coordination, outreach, and monitoring. We commend the agencies for  their efforts and believe it is important for them to complete these efforts  in order to establish a more formalized approach.

Regarding our second recommendation that FERC assess the adequacy  of existing RTO market rules, and similar rules at non-RTO system  planners, FERC stated that it continually assesses the rules of entities  over which it has jurisdiction and that it has specifically explored whether  changes are needed to respond to the regulations. In particular, FERC  noted that it asked participants at a 2011 technical conference to address  whether changes were needed in market rules and that the response  from panelists and commenters was that no significant changes were  needed. Our observation from attending this conference is that it fostered  a useful exchange of ideas and perspectives. However, we do not believe  it is a substitute for an assessment by FERC of the adequacy of rules.  FERC also noted that several recent rulemakings may lead to changes in  rules that may be beneficial in the context of the EPA regulations, such as  in how information is gathered regarding retirements and how demand  response is encouraged. These are also positive steps, but they do not  constitute an assessment of whether RTO market rules need to be  modified to ensure timely, cost-effective mitigation of potential reliability  challenges that may be associated with responses to the regulations.

In addition, FERC, DOE, and EPA provided technical comments and  clarifications, which we incorporated as appropriate.

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, Chairman of FERC,  Administrator of the EPA, 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 Frank Rusco at (202) 512-3841 or ruscof@gao.gov or David  Trimble at (202) 512-3841 or trimbled@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 who made key contributions to this  report are listed in appendix VIII.

This report provides information on the implications associated with four  key recently proposed or finalized regulations from the Environmental  Protection Agency (EPA): (1) the Cross-State Air Pollution Rule (CSAPR);  (2) the Mercury and Air Toxics Standards (MATS); (3) the proposed  Cooling Water Intake Structures at Existing and Phase I Facilities  regulation, also known as 316(b), and (4) the proposed Disposal of Coal  Combustion Residuals from Electric Utilities regulation (CCR).  Specifically, this report addresses: (1) what available information  indicates about actions power companies may take at coal-fueled  generating units in response to the four key EPA regulations; (2) what  available information indicates about these regulations’ potential  implications on the electricity market and reliability; and (3) the extent to  which EPA, FERC, DOE, and other stakeholders can mitigate adverse  electricity market and reliability implications, if any, associated with  requirements in these regulations.

To provide available information on actions power companies may take in  response to these regulations and their potential market and reliability  implications, we (1) selected for review 12 studies of companies’  projected responses to the regulations, as well as the potential impacts of  these responses, and (2) analyzed data from Ventyx Velocity Suite on  electricity generating units. We considered several factors in selecting  these studies including how closely they reflected the four regulations,  and we prioritized studies published after significant changes in the  regulations, and those from independent groups or federal agencies. We  also selected certain studies that provided information on specific aspects  of our review, such as those with estimates of price implications and that  contained regional assessments. The studies we selected were carried  out by EPA, the Energy Information Administration, system planners,  research organizations, and a consulting firm. (Selected studies are listed  in app. III.) We took several steps to evaluate the reasonableness of the  studies’ assumptions and methodologies, including reviewing descriptions  of the policy scenarios that formed the basis of the studies’ analysis. In  some cases, we identified differences between study assumptions and  the regulations themselves, which we note in the text where appropriate.  Some of these studies analyze several scenarios, and we report results  from those scenarios which we felt best reflect the regulations. The actual  price and reliability implications of these four regulations will depend on  various uncertain factors, such as future market conditions and the  ultimate regulatory requirements, but we determined that these studies  were reasonable for describing what is known about the range of potential  actions power companies may take and implications of the four  regulations.

We also analyzed data from Ventyx Velocity Suite EV Market-Ops  database to describe characteristics of coal-fueled generating units and to  provide information on historic and planned retrofits and retirements of  such units. We reviewed this data as of April 9, 2012, from all operating  units that had capacity greater than 25 megawatts, making them subject  to MATS and CSAPR. In all, we examined the characteristics of 1,050  coal-fueled electricity generating units, accounting for 99 percent of all  coal-fueled capacity and 75 percent of coal-fueled units. We classified  detailed air pollution controls into control types, and reviewed our  classifications with officials at Ventyx, the Department of Energy (DOE),  and EPA. Information regarding planned retrofits and retirements reflect  publicly reported plans as identified by Ventyx. As plans may change,  actual future retrofits and retirements may differ from the data in these  plans. To assess the reliability of the Ventyx data, we reviewed existing  documentation about the data and the system that produced them,  interviewed Ventyx staff who were knowledgeable about the data,  consulted with EPA and DOE officials and other knowledgeable parties,  conducted some electronic testing, and compared data in Ventyx to  information obtained from several power companies and regional  transmission organizations. We determined the Ventyx data to be  sufficiently reliable for the purpose of this report.

To examine the extent to which industry, regulators, and other  stakeholders can mitigate adverse implications, we interviewed officials at  the Federal Energy Regulatory Commission (FERC), DOE, North  American Electric Reliability Corporation, and EPA to better understand  what steps they had taken to mitigate potential reliability and price  challenges and additional options for doing so. We reviewed relevant  laws, regulations, and agency documentation for information on agency  authorities, responsibilities with respect to the EPA regulations, and  options for mitigating adverse reliability concerns. We conducted multiple  interviews with system planners and operators in both restructured and  traditionally regulated markets that are expected to be significantly  affected by the regulations to understand the tools they had available for  managing electric reliability and prices.

To address all three objectives, we summarized the results of  semistructured interviews with a nonprobability sample of 33  stakeholders. (See app. II for a list of these stakeholders.) We selected  these stakeholders to be broadly representative of differing perspectives  on these issues based on recommendations, including from FERC, DOE,  and industry associations, and other factors. In particular, we obtained  views and information from staff at power companies that may be affected  by these regulations, regional transmission organizations, and officials in  six states—Georgia, Kentucky, Missouri, Ohio, Pennsylvania, and  Texas—to understand the role of these state agencies in addressing the  reliability and price implications of the regulations. To select states and  companies, we considered, among other factors, the amount of state and  companies’ electricity generating capacity that is coal-fueled. We also  sought a balance of states and companies in and out of RTO regions that  were traditionally regulated and restructured. We provided a preliminary  list of the stakeholders we intended to interview to FERC and EPA, and  we incorporated their suggestions in considering stakeholders where  appropriate. Because we used a nonprobability sample, the views of  these stakeholders are not generalizable to all potential stakeholders, but  they provide illustrative examples.

We conducted this performance audit from July 2011 to July 2012 in  accordance with generally accepted government auditing standards.  Those standards require that we plan and perform the audit to obtain  sufficient, appropriate evidence to provide a reasonable basis for our  findings and conclusions based on our audit objectives. We believe that  the evidence obtained provides a reasonable basis for our findings and  conclusions based on our audit objectives.

State Electricity and Environmental Regulators

Burtraw, Dallas, Karen Palmer, Anthony Paul, and Matt Woerman (RFF).  “Secular Trends, Environmental Regulations, and Electricity Markets.”  Resources for the Future Discussion Paper. DP12-15. Washington, D.C.:  March 2012.

Energy Information Administration (EIA). Annual Energy Outlook 2012  Early Release Overview. DOE/EIA-0383ER. Washington, D.C.: January  23, 2012.

Environmental Protection Agency (EPA-316b). Economic and Benefits  Analysis for Proposed Section 316(b) Existing Facilities Rule. EPA 821-R- 11-003. March 28, 2011.

Environmental Protection Agency (EPA-CCR). Regulatory Impact  Analysis For EPA’s Proposed RCRA Regulation Of Coal Combustion  Residues (CCR) Generated by the Electric Utility Industry. Washington,  D.C.: April 30, 2010.

Environmental Protection Agency (EPA-CSAPR). Regulatory Impact  Analysis for the Federal Implementation Plans to Reduce Interstate  Transport of Fine Particulate Matter and Ozone in 27 states; Correction of  SIP Approvals for 22 States. June 2011.

Environmental Protection Agency (EPA-MATS). Regulatory Impact  Analysis for the Final Mercury and Air Toxics Standards. EPA-452/R-11- 011. Research Triangle Park, NC: December 2011.

IHS Global Insight. US Energy Outlook. September 2011.

Macedonia, Jennifer, Joe Kruger, Lourdes Long, and Meghan  McGuinness (Bipartisan Policy Center). Environmental Regulation and  Electric System Reliability. Washington, D.C.: Bipartisan Policy Center,  June 13, 2011.

Midwest Independent Transmission System Operator. (MISO). EPA  Impact Analysis: Impacts from the EPA Regulations on MISO. October  2011.

NERA Economic Consulting (NERA). Potential Impacts of EPA Air, Coal  Combustion Residuals, and Cooling Water Regulations. Prepared for the  American Coalition for Clean Coal Electricity. Boston, MA: September  2011.

North American Electric Reliability Corporation (NERC). 2011 Long-Term  Reliability Assessment. November 2011.

PJM Interconnection (PJM). Coal Capacity at Risk for Retirement in PJM:  Potential Impacts of the Finalized EPA Cross State Air Pollution Rule and  Proposed National Emissions Standards for Hazardous Air Pollutants.  August 26, 2011.

Appendix IV: Additional Information on Coal-Fueled Electricity Generating Units

Figure 8 shows the distribution of the nation’s coal-fueled electricity  generating units by the territories of eight regional reliability entities that  set and enforce reliability standards for the electricity industry.

Various air pollution controls are used at electricity generating units to  reduce emissions of air pollutants by either reducing the formation of  these emissions or capturing them after they are formed. At coal power  plants, these controls are generally installed in either the boiler, where  coal is burned, or the ductwork that connects a boiler to the stack. A  single power plant can use multiple boilers to generate electricity, and the  emissions from multiple boilers can sometimes be connected to a single  stack. The reduction in emissions from a coal-fueled generating unit by  the use of pollution controls can be substantial, as shown in table 4.  Controls may be capable of removing multiple pollutants. For example, a  wet scrubber can control both sulfur dioxide (SOFigure 9 shows the capacity of coal-fueled generating units that were  retrofitted with select controls from 2000 through 2011, and figures 10  and 11 show the percent of generating capacity with select controls by  region.

Appendix V: Comments from the Federal Energy Regulatory Commission

1.  We recognize that FERC has taken a number of positive actions  related to the EPA regulations, and we have described these in our  draft and final report. We have made some clarifying changes and, in  one case, added language about an example we had not previously  described in the report in response to these comments.  2.  The scope of FERC's policy statement is limited to describing how  FERC intends to provide advice to EPA on requests for administrative  orders to bring a source into compliance with MATS within 1 year. It  provides a useful description of FERC's role with respect to this tool  for addressing potential reliability challenges, but it does not establish  a formal, documented process for FERC's overall monitoring effort or  for its coordination with EPA and DOE. We added a description of  FERC's policy statement where we describe FERC's role with respect  to MATS in response to this comment. 3.  We agree that multiagency coordination can be difficult. When we met  with FERC, EPA, and DOE during the course of our audit work, the  agencies had not documented a formal process for monitoring. In  response to our draft report, these agencies said they are working to  establish such an approach. We commend these agencies for taking  this step and believe it is important that they complete this effort. We  acknowledge there may be limits on the extent to which agencies can  collaborate and clarified our recommendation accordingly. 4.  We acknowledge that FERC has gathered views on the potential  implications of these regulations from various affected parties,  including at formal events such as FERC's 2011 technical conference  and the February 2012 forum with state regulators. Our observation  from attending these events is that they fostered a useful exchange of  ideas and perspectives about the potential implications of the EPA  regulations. However, the actual implications will only be known once  electricity generating unit owners finalize their plans for responding to  the regulations and begin to take steps to retrofit or retire units—which  will occur over the next several years. We believe that additional  monitoring will be important and that the actions noted by FERC do  not represent the type of formal, documented process that will be  needed for successfully monitoring industry's progress in responding  to the regulations or for FERC’s coordination with DOE and EPA in  this effort. We believe there are risks to relying on informal  mechanisms and that a formal, documented process could help  strengthen FERC's future efforts at identifying potential problems. As  such, we made no changes in response to this comment. 5.  We believe that the NERC-overseen reliability assessments, plans  and reports from other stakeholders, as well as conferences and  workshops, can all be useful in an overall monitoring effort. We  encourage FERC to work with NERC and other stakeholders in  monitoring industry progress to the extent that FERC determines such  activities to be useful. We maintain that FERC should formalize this  process and document it if the agency intends for this monitoring to  continue in the future. We made no change in response to this  comment. 6.  We acknowledge that FERC periodically performs various  assessments of the adequacy of existing RTO market rules and  similar rules of non-RTO system planners and, where FERC believes  it is appropriate, encourages changes. However, based on our  conversations with FERC officials, FERC had not proactively  assessed the adequacy of system planner rules in light of the EPA  regulations to determine whether changes are needed or if  improvements at one system planner could be useful at another. We  also acknowledge that there was a useful exchange of ideas and  perspectives about the need for potential changes in market rules at  FERC's technical conference, but we do not believe that the gathering  of these views is a substitute for an assessment by FERC of the  adequacy of these rules. In addition, FERC's recent rulemakings are  positive steps, but they do not reflect an assessment of whether rules  need to be modified in light of the EPA regulations to ensure timely,  cost-effective mitigation of potential reliability challenges that may be  associated with the regulations. We made no change in response to  this comment. 7.  Neither the draft report, nor the final report recommends that FERC  consider the presence or absence of demand response when making  key decisions about electricity markets. FERC’s comment refers to  text in our draft report that referred to a recommendation in our 2004  report on demand response. We made this reference to highlight that  demand response is a tool that could lower demand for electricity to  mitigate the price or reliability implications of the EPA regulations and  to note that FERC has taken a number of steps to facilitate broader  use of demand response among RTOs. As noted in the conclusion of  this report, we believe that demand response could provide an  important mechanism that could mitigate potential reliability  challenges, should they arise. As such, it may be useful for FERC to  consider whether there are certain approaches related to demand  response at one or more RTOs that could be encouraged elsewhere  or whether the presence or adequacy of demand response in a  market should be used when making decisions regarding market  rules. We made no change in response to this comment.  8.  We do not suggest that a one-size-fits-all approach would be best,  and believe efforts to develop the RTOs and other institutions requires  leveraging prior entities' experiences. FERC may have the opportunity  to take a more proactive role in narrowing these differences to the  benefit of market participants overseen by FERC and the consumers  who are ultimately served by these markets. We made no change in  response to this comment. 9.  We do not assert that FERC will be unable to meet its statutory  deadlines for review of transmission investments and reliability must- run agreements. Rather, we suggest that information from a formal,  documented monitoring effort could help alert agencies in advance if a  larger or smaller than expected number of reliability challenges arises,  which could be useful for managing its staffing and operations. We  made no change in response to this comment. 10. We agree that FERC’s policy statement provides clarity about the  process FERC intends to take to provide timely comments to EPA on  requests for administrative orders to bring a source into compliance  with MATS within 1 year. However, we continue to believe that a  documented, formal monitoring process—by giving FERC insight into  the extent of potential reliability challenges—could aid FERC in  managing its process for providing input to EPA. We made no change  in response to this comment.

Appendix VI: Comments from the Department of Energy

Appendix VII: Comments from the Environmental Protection Agency

Appendix VIII: GAO Contacts and Staff Acknowledgments

In addition to the individuals named above, Jon Ludwigson (Assistant  Director), Mike Armes, Melinda Cordero, Philip Farah, Quindi Franco,  Cindy Gilbert, Paige Gilbreath, Michael Hix, Mitch Karpman, Karen  Keegan, Alison O’Neill, Madhav Panwar, Kendal Robinson, Jeanette  Soares, and Kiki Theodoropoulos made key contributions to this report.

Question: How will power companies respond to EPA regulations?

Answer: It is uncertain how power companies may respond to four key Environmental Protection Agency (EPA) regulations, but available information suggests companies may retrofit most coal-fueled generating units with controls to reduce pollution, and that 2 to 12 percent of coal-fueled capacity may be retired.

Question: How will these regulations affect certain regions more than others?

Answer: Some regions may see more significant levels of retirements. For example, one study examined 11 states in the Midwest and projected that 18 percent of coal-fueled capacity in that region could retire.

Question: Without EPA regulations, how likely would retirements be?

Answer: EPA and some stakeholders GAO interviewed stated that some such retirements could occur as a result of other factors such as lower natural gas prices, regardless of the regulations. Power companies may also build new generating units, upgrade transmission systems to maintain reliability, and increasingly use natural gas to produce electricity as coal units retire and remaining coal units become somewhat more expensive to operate.

Background
Role of Coal in Electricity Generation

Power Companies Are Expected to Retrofit or Retire Units and Take Other Actions

Power Companies Are Expected to Retrofit Many Generating Units, Retire Others, and Take Additional Actions

Actions Taken by Power Companies Will Likely Increase Electricity Prices and May Contribute to Reliability Challenges in Some Regions

Actions Would Likely Increase Electricity Prices in Some Regions

Question: How will these actions affect electricity prices?

Answer: Available information suggests these actions would likely increase electricity prices in some regions.

Question: How will these actions affect electricity reliability?

Answer: Furthermore, while these actions may not cause widespread reliability concerns, they may contribute to reliability challenges in some regions.

Question: How might price changes differ based on location?

Answer: Regarding prices, the studies GAO reviewed estimated that increases 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.

Question: How might prices be affected in the long term?

Answer: According to EPA officials, the agency’s estimates of price increases would be within the historical range of price fluctuations, and projected future prices may be below historic prices.

Question: How likely are reliability challenges?

Answer: Regarding reliability, these actions are not expected to pose widespread concerns but may contribute to challenges in some regions. EPA and some stakeholders GAO interviewed indicated that these actions should not affect reliability given existing tools.

Question: What reliability challenges were identified?

Answer: Some other stakeholders GAO interviewed identified potential reliability challenges. Among other things, it may be difficult to schedule and complete all retrofits to install controls and to resolve all potential reliability concerns associated with retirements within compliance deadlines.

Question: How could the adverse effects of the regulations be mitigated?

Answer: Existing tools could help mitigate many, though not all, of the potential adverse implications associated with the four EPA regulations, but the Federal Energy Regulatory Commission (FERC), Department of Energy (DOE), and EPA do not have a joint, formal process to monitor industry’s progress in responding to the regulations.

Question: How could potential price increases be addressed?

Answer: Some tools, such as state regulatory reviews to evaluate the prudence of power company investments, may address some potential price increases.

Question: How could potential reliability issues be addressed?

Answer: Furthermore, tools available to industry and regulators, as well as certain regulatory provisions, may address many potential reliability challenges. However, because of certain limitations, these tools may not fully address all challenges where generating units needed for reliability are not in compliance by the deadlines.

Question: What actions have the FERC, DOE, and EPA taken to mitigate the adverse implications of this regulation?

Answer: FERC, DOE, and EPA have responsibilities concerning the electricity industry, and they have taken important first steps to understand these potential challenges by, for example, informally coordinating with power companies and others about industry’s actions to respond to the regulations. However, they have not established a formal, documented process for jointly and routinely monitoring industry’s progress and, absent such a process, the complexity and extent of potential reliability challenges may not be clear to these agencies.

Question: What might result from the lack of formal process?

Answer: This may make it more difficult to assess whether existing tools are adequate or whether additional tools are needed.

Existing Tools Could Mitigate Many Adverse Implications, but Agencies Do Not Have a Formal Process to Monitor Industry Progress Toward Compliance

Available Tools May Help Mitigate Some, but Not All, Price Increases

Available Tools Could Address Many, but Not All, Reliability Challenges

Agencies Have Begun Taking Steps to Monitor Industry’s Progress but Have Not Documented Their Process, and FERC Has Not Proactively Reviewed RTO Rules

Question: What EPA regulations will affect coal-fueled electric plants?

Answer: EPA recently proposed or finalized four regulations affecting coal-fueled electricity generating units, which provide almost half of the electricity in the United States: (1) the Cross-State Air Pollution Rule; (2) the Mercury and Air Toxics Standards; (3) the proposed Cooling Water Intake Structures regulation; and (4) the proposed Disposal of Coal Combustion Residuals regulation.

Question: How will power companies respond to these regulations?

Answer: Power companies may retrofit or retire some units in response to the regulations.

Question: How will these regulations be beneficial?

Answer: EPA estimated two of the regulations would prevent thousands of premature deaths and generate $160-$405 billion in annual benefits.

Question: Why is there concern about the affects of these regulations?

Answer: Some stakeholders have expressed concerns that these regulations could increase electricity prices and compromise reliability—the ability to meet consumers' demand.

Question: What aspects of these regulations was GAO asked to examine?

Answer: GAO was asked to examine: (1) actions power companies may take in response to these regulations; (2) their potential electricity market and reliability implications; and (3) the extent to which these implications can be mitigated.

Question: How did GAO source data for the report?

Answer: GAO reviewed agency documents, selected studies, and interviewed stakeholders.

Federal and State Government Roles in Electricity Markets