EPA Regulations and Electricity: Better Monitoring by Agencies Could Strengthen Efforts to Address Potential Challenges
Released: 2012-08-16T00:00:00

Letter

Background

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.

Role of Coal in Electricity Generation

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.

Damage to Aquatic Life: 316(b)

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.

In addition, this tool would not

Clean Air Act consent decrees.

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.

Conclusions

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.

Recommendations for Executive Action

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.

Agency Comments and Our Evaluation

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.

Appendix I: Scope and Methodology

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.

Appendix II: List of Stakeholders

Federal Agencies

State Electricity and Environmental Regulators

Power Companies

Other

Appendix III: List of Studies

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

GAO Comments

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

GAO Contacts

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.