EPA REGULATIONS 

AND ELECTRICITY 

Better Monitoring by 

Agencies Could 

Strengthen Efforts to 

Address Potential 

Challenges 

Report to the Chairman, Committee on 

Commerce, Science, and 

Transportation, U.S. Senate 

July 2012 

GAO-12-635 

United States Government Accountability Office

GAO 
United States Government Accountability Office

Highlights of GAO-12-635, a report to the 

Chairman, Committee on Commerce, Science, 

and Transportation, U.S. Senate

July 2012

EPA REGULATIONS AND ELECTRICITY

Better Monitoring by Agencies Could Strengthen 

Efforts to Address Potential Challenges 

Why GAO Did This Study

EPA recently proposed or finalized four 

regulations affecting coal-fueled 

electricity generating units, which 

provide almost half of the electricity in 

the United States: (1) the Cross-State 

Air Pollution Rule; (2) the Mercury and 

Air Toxics Standards; (3) the proposed 

Cooling Water Intake Structures 

regulation; and (4) the proposed 

Disposal of Coal Combustion 

Residuals regulation. Power 

companies may retrofit or retire some 

units in response to the regulations. 

EPA estimated two of the regulations 

would prevent thousands of premature 

deaths and generate $160-$405 billion 

in annual benefits. Some stakeholders 

have expressed concerns that these 

regulations could increase electricity 

prices and compromise reliability—the 

ability to meet consumers' demand. 

FERC and others have oversight over 

electricity prices and reliability. DOE 

can order a generating unit to run in 

certain emergencies. 

GAO was asked to examine: (1) 

actions power companies may take in 

response to these regulations; (2) their 

potential electricity market and 

reliability implications; and (3) the 

extent to which these implications can 

be mitigated. GAO reviewed agency 

documents, selected studies, and 

interviewed stakeholders.

What GAO Recommends

GAO recommends, among other 

things, that FERC, DOE, and EPA take 

additional steps to monitor industry’s 

progress in responding to the 

regulations. DOE and EPA agreed with 

this recommendation, and FERC 

disagreed with this and another 

recommendation. GAO continues to 

believe that it is important for FERC to 

take the recommended actions.

What GAO Found

It is uncertain how power companies may respond to four key Environmental 

Protection Agency (EPA) regulations, but available information suggests 

companies may retrofit most coal-fueled generating units with controls to reduce 

pollution, and that 2 to 12 percent of coal-fueled capacity may be retired. Some 

regions may see more significant levels of retirements. For example, one study 

examined 11 states in the Midwest and projected that 18 percent of coal-fueled 

capacity in that region could retire. EPA and some stakeholders GAO interviewed 

stated that some such retirements could occur as a result of other factors such 

as lower natural gas prices, regardless of the regulations. Power companies may 

also build new generating units, upgrade transmission systems to maintain 

reliability, and increasingly use natural gas to produce electricity as coal units 

retire and remaining coal units become somewhat more expensive to operate. 

Available information suggests these actions would likely increase electricity 

prices in some regions. Furthermore, while these actions may not cause 

widespread reliability concerns, they may contribute to reliability challenges in 

some regions. Regarding prices, the studies GAO reviewed estimated that 

increases could vary across the country, with one study projecting a range of 

increases from 0.1 percent in the Northwest to an increase of 13.5 percent in 

parts of the South more dependent on electricity generated from coal. According 

to EPA officials, the agency’s estimates of price increases would be within the 

historical range of price fluctuations, and projected future prices may be below 

historic prices. Regarding reliability, these actions are not expected to pose

widespread concerns but may contribute to challenges in some regions. EPA and 

some stakeholders GAO interviewed indicated that these actions should not 

affect reliability given existing tools. Some other stakeholders GAO interviewed 

identified potential reliability challenges. Among other things, it may be difficult to 

schedule and complete all retrofits to install controls and to resolve all potential 

reliability concerns associated with retirements within compliance deadlines.

Existing tools could help mitigate many, though not all, of the potential adverse 

implications associated with the four EPA regulations, but the Federal Energy 

Regulatory Commission (FERC), Department of Energy (DOE), and EPA do not 

have a joint, formal process to monitor industry’s progress in responding to the 

regulations. Some tools, such as state regulatory reviews to evaluate the 

prudence of power company investments, may address some potential price 

increases. Furthermore, tools available to industry and regulators, as well as 

certain regulatory provisions, may address many potential reliability challenges. 

However, because of certain limitations, these tools may not fully address all 

challenges where generating units needed for reliability are not in compliance by 

the deadlines. FERC, DOE, and EPA have responsibilities concerning the 

electricity industry, and they have taken important first steps to understand these 

potential challenges by, for example, informally coordinating with power 

companies and others about industry’s actions to respond to the regulations. 

However, they have not established a formal, documented process for jointly and 

routinely monitoring industry’s progress and, absent such a process, the 

complexity and extent of potential reliability challenges may not be clear to these 

agencies. This may make it more difficult to assess whether existing tools are 

adequate or whether additional tools are needed. 

View GAO-12-635. For more information, 

contact Frank Rusco at (202) 512-3841 or 

ruscof@gao.gov or David Trimble at (202) 

512-3841 or trimbled@gao.gov.
Page i GAO-12-635 EPA Regulations and Electricity

Letter 1 

Background 5

Power Companies Are Expected to Retrofit or Retire Units and 

Take Other Actions 24

Actions Taken by Power Companies Will Likely Increase 

Electricity Prices and May Contribute to Reliability Challenges 

in Some Regions 31

Existing Tools Could Mitigate Many Adverse Implications, but 

Agencies Do Not Have a Formal Process to Monitor Industry 

Progress Toward Compliance 46

Conclusions 62

Recommendations for Executive Action 63

Agency Comments and Our Evaluation 64

Appendix I Scope and Methodology 67

Appendix II List of Stakeholders 70

Appendix III List of Studies 72

Appendix IV Additional Information on Coal-Fueled Electricity Generating 

Units 74

Appendix V Comments from the Federal Energy Regulatory Commission 82

Appendix VI Comments from the Department of Energy 92

Appendix VII Comments from the Environmental Protection Agency 94

Contents
Page ii GAO-12-635 EPA Regulations and Electricity

Appendix VIII GAO Contacts and Staff Acknowledgments 99

Tables

Table 1: Major Milestones, Benefits and Costs of Four Key EPA 

Regulations 8

Table 2: EPA Estimates of Potential Average National and Regional 

Retail Electricity Price Increases Due to Compliance with 

Four Key EPA Regulations 39

Table 3: Selected Concerns about RTO Market Rules Arising from 

the EPA Regulations and Other Industry Factors 61

Table 4: Summary of Air Pollution Control Equipment Used at 

Coal-Fueled Electricity Generating Units 76

Figures

Figure 1: Percentage of Electricity Generated from Coal by State, 

2010 7

Figure 2: States Covered by CSAPR 12

Figure 3: U.S. Regional Transmission Organizations 19

Figure 4: Sample Layout of Controls at a Coal-Fueled Power Plant 28

Figure 5: Capacity of Actual and Planned Coal-Fueled Generating 

Unit Retirements, 1990-2020 30

Figure 6: Installation of a Scrubber at the Cardinal Plant in 

Brilliant, Ohio 36

Figure 7: Location and Capacity of Planned Coal-Fueled Generating 

Unit Retrofits and Retirements through 2020, as of April 

9, 2012 43

Figure 8: Capacity and Share of Total Capacity from Coal-Fueled 

Electricity Generating Units by Region, as of April 9, 2012 74

Figure 9: Capacity of Coal-Fueled Generating Units Retrofitted 

with Select Air Pollution Controls, 2000-2011 77

Figure 10: Percentage of Coal-Fueled Generating Capacity with Air 

Pollution Controls Installed by Region, as of April 9, 2012 78

Figure 11: Percentage of Coal-Fueled Generating Capacity with Air 

Pollution Controls Installed by Region, as of April 9, 2012 80
Page iii GAO-12-635 EPA Regulations and Electricity

Abbreviations

ACI activated carbon injection unit

CAIR Clean Air Interstate Rule

CCR Coal Combustion Residuals Regulation

CSAPR Cross-State Air Pollution Rule

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

ERCOT Electric Reliability Council of Texas

ESP electrostatic precipitator

FERC Federal Energy Regulatory Commission

ISO Independent System Operator

MATS Mercury and Air Toxics Standards

MISO Midwest Independent Transmission System Operator, Inc.

MW megawatt

NERC North American Electric Reliability Corporation

NOx

PJM PJM Interconnection

 nitrogen oxides

RFF Resources for the Future

RTO Regional Transmission Organization

SCR selective catalytic reduction unit

SNCR selective non-catalytic reduction unit

SO2 sulfur dioxide

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Page 1 GAO-12-635 EPA Regulations and Electricity

United States Government Accountability Office

Washington, DC 20548

July 17, 2012

The Honorable John D. Rockefeller IV

Chairman

Committee on Commerce, Science, 

 and Transportation

United States Senate

Dear Mr. Chairman:

Coal is an abundant and widely used fuel source in the United States, 

producing about 42 percent of the nation’s electricity supply in 2011. 

Coal-fueled power plants have historically been among the least costly 

sources of electricity in the country. However, burning coal and other 

fossil fuels (i.e., natural gas and oil) to produce electricity is associated 

with human health and environmental concerns. For example, fossil fuel 

electricity generating units are among the largest emitters of sulfur dioxide 

(SO2) and nitrogen oxides (NOx), which have been linked to respiratory 

illnesses and acid rain and which may travel great distances and affect air 

quality in states downwind from generating units—downwind states.1

.

In 

2008, the last year for which EPA has such comprehensive information, 

coal-fueled units emitted about 48 percent of the nation’s mercury, a 

hazardous air pollutant and heavy metal linked to neurological disorders 

in children and harm to wildlife In addition, coal-fueled generating units 

emit large quantities of carbon dioxide, the primary greenhouse gas 

contributing to climate change, and can use significant quantities of water 

and create large amounts of waste products that require disposal.

To address concerns over air pollution, water resources, and solid waste, 

several environmental laws, including the Clean Air Act, Clean Water Act, 

and Resource Conservation and Recovery Act, were enacted. As 

required or authorized by these laws, the Environmental Protection 

Agency (EPA), the primary federal agency responsible for implementing 

many of the nation’s environmental laws, recently proposed or finalized 

 

1

An electricity generating unit consists of any combination of an electricity generator, 

reactor, boiler, combustion turbine, or other equipment operated together to produce 

electrical power. A power plant is a facility with one or more generating units, together with 

other equipment used to produce electric power. 

 
 

Page 2 GAO-12-635 EPA Regulations and Electricity

four key regulations that will affect coal-fueled units.2

These four regulations have potentially significant implications for public 

health and the environment. In particular, EPA projects that, among other 

benefits, CSAPR would reduce SO2 emissions by 73 percent and NOx

emissions by over half in covered states, reducing asthma and related 

human health impacts. In addition, EPA projects that MATS would reduce

mercury emissions by 75 percent from coal-fueled electricity generating 

units, reducing the impacts of mercury on adults and children. In 2016, 

EPA estimates that the final versions of MATS and CSAPR could 

generate $160 billion to $405 billion in monetized annual benefits (in 2011 

year dollars), preventing tens of thousands of premature deaths and 

reducing pollution-related illnesses.

These four 

regulations are: (1) the Cross-State Air Pollution Rule (CSAPR), which 

prohibits certain emissions of air pollutants in 28 states because of the 

impact they would have on air quality in other states; (2) the National 

Emissions Standards for Hazardous Air Pollutants from Coal and Oil 

Fired Electric Utility Steam Generating Units, also known as the Mercury 

and Air Toxics Standards (MATS), which establishes emissions 

limitations on mercury and other toxic pollutants; (3) the proposed Cooling 

Water Intake Structures at Existing Facilities and Phase I Facilities 

regulation, which we refer to as 316(b), which would establish 

requirements for water withdrawn and used for cooling purposes that 

reflect the best technology available to minimize adverse environmental 

impact; and (4) the proposed Disposal of Coal Combustion Residuals 

from Electric Utilities regulation (CCR), which would govern the disposal 

of coal combustion residuals, such as coal ash, in landfills or surface 

impoundments.

3

These four regulations could also have significant implications for the 

electricity industry. Generating units fueled by coal—which comprise a 

 

2

On April 13, 2012, EPA proposed new source performance standards for greenhouse 

gas emissions from certain new fossil fuel electricity generating units, but the standards 

would not apply to existing units. We do not discuss this proposed regulation in this report.

3

Unless otherwise noted, all dollar estimates presented in this report have been converted 

to 2011 year dollars using the gross domestic product deflator based on the calendar 

year. EPA’s estimates of the benefits of the regulations presented here refer to monetized 

benefits. As not all benefits can be monetized, these may represent a subset of overall 

benefits of the regulations. We did not independently assess EPA’s estimates of the 

benefits of these regulations. 
 

Page 3 GAO-12-635 EPA Regulations and Electricity

large portion of the national electricity supply—are expected to be 

affected by the four proposed regulations. Power companies might retrofit 

some generating units with controls to reduce pollutants4 and, when it is 

not economic to retrofit, may retire some generating units, according to 

EPA.5 Several representatives from power companies and officials from 

federal and state regulatory agencies have expressed concerns that, as 

companies incur additional costs in responding to these regulations, and 

as the electricity supply is affected by generating unit retirements, 

electricity prices could increase and reliability—the ability to meet 

consumers’ electricity demand—could be compromised.6

Federal agencies and other stakeholders have some responsibilities for 

overseeing actions power companies take in response to the regulations 

and have a role in mitigating some potential adverse implications. The 

Federal Energy Regulatory Commission (FERC) is generally responsible 

for ensuring that certain electricity and transmission prices are “just and 

reasonable,” as well as approving and enforcing standards for reliability in 

the bulk power system––the interconnected transmission system 

combined with the electric power from generating units needed to 

maintain the system. The Department of Energy (DOE) works to 

modernize the electricity system, enhance the security and reliability of 

the nation’s energy infrastructure, and facilitate recovery from any 

disruptions. DOE also has authority to compel generating units to produce 

electricity in certain emergency situations. Other stakeholders also play 

key roles, such as state environmental and electricity regulators and 

system planners that coordinate planning decisions regarding 

transmission and generation infrastructure to maintain the reliable supply 

 

4

Compliance with the four key regulations may involve using various technologies. It may 

also include making infrastructure changes to reduce environmental impacts; for example, 

installing liners at facilities used to store coal combustion residuals to minimize leaching of 

contaminants into groundwater. We refer to all of these as controls. 

5

Multiple types of power companies exist in the electricity industry, including owners of 

electricity generating units and owners of transmission systems, as well as integrated 

companies that own both generation and transmission. In addition, some companies sell 

electricity directly to customers; these companies may or may not own any generating 

units or transmission systems. We generally use the term power company to refer to those 

companies that own generation and may or may not also own transmission.

6

We use the term “responding to the regulations” to refer to such actions as installing 

controls, retiring units, and other actions such as building new generating capacity to 

replace that lost in retirements. 
 

Page 4 GAO-12-635 EPA Regulations and Electricity

of electricity to consumers.7

In this context, you asked us to provide information on the implications of 

the four key recently proposed or finalized EPA regulations. Our 

objectives were to examine: (1) what available information indicates about 

actions power companies may take at coal-fueled generating units in 

response to the four key EPA regulations; (2) what available information 

indicates about these regulations’ potential implications on the electricity 

market and reliability; and (3) the extent to which EPA, FERC, DOE, and 

other stakeholders can mitigate adverse electricity market and reliability 

implications, if any, associated with requirements in these regulations.

In a December 2011 memorandum, the 

President directed EPA to, among other things, promote early, 

coordinated, and orderly planning and execution of the measures needed 

to implement MATS while maintaining electricity reliability, including 

coordination with DOE, FERC and others.

To examine what available information indicates about actions power 

companies may take in response to these regulations and their potential 

market and reliability implications, we (1) selected for review 12 studies of 

companies’ projected responses to the regulations and the potential 

impacts of these responses and (2) analyzed data from Ventyx Velocity 

Suite on electricity generating units. We considered several factors in 

selecting studies, including how closely they reflect the four regulations, 

and we assessed the reasonableness of the studies’ assumptions and 

methodologies. The studies we selected were carried out by EPA, the 

Energy Information Administration (EIA), system planners, research 

organizations, and a consulting firm.

8

 

7

In this report, we use the term “system planner” to refer to those entities with 

responsibility for advance planning to ensure there are adequate transmission and 

generation resources to meet demand while operating the grid reliably. This usage does 

not directly align with planning terminology used by the North American Electric Reliability 

Corporation (NERC). 

In some cases, we identified 

differences between study assumptions and the regulations, which we 

note in the text where appropriate. The actual pricing and reliability 

implications of these regulations will depend on various uncertain factors, 

such as future market conditions and the ultimate regulatory 

requirements, but we determined that these studies were reasonable for 

describing what is known about the range of potential implications of the 

8

EIA is a statistical agency within DOE that collects, analyzes, and disseminates 

independent information on energy issues.
 

Page 5 GAO-12-635 EPA Regulations and Electricity

four regulations. We used data from Ventyx Velocity Suite, as of April 9, 

2012, to describe coal-fueled generating units and to provide information 

on historic and planned retrofits and retirements of such units. Ventyx 

Velocity Suite is a proprietary database containing consolidated energy 

data from EIA, EPA, and other sources. Information regarding planned 

retrofits and retirements reflect publicly reported plans as identified by 

Ventyx. As plans may change, actual future retrofits and retirements may 

differ from the data in these plans. To examine the extent to which 

agencies and other stakeholders can mitigate any adverse implications, 

we interviewed officials at the EPA, FERC, and DOE, and reviewed 

relevant documents. To address all three objectives, we summarized the 

results of semistructured interviews with a nonprobability sample of 33 

stakeholders, including officials from EPA, FERC, and DOE; 

representatives of power companies; regional transmission system 

operators; state regulators; and researchers. We selected these 

stakeholders to be broadly representative of differing perspectives on 

these issues based on recommendations from EPA, FERC, DOE, 

industry associations and such factors as the percentage of companies’ 

generating capacity that is coal-fueled. We provided a preliminary list of 

the stakeholders we intended to interview to FERC and EPA, and we 

incorporated their suggestions in considering stakeholders where 

appropriate. Because we used a nonprobability sample, the views of 

these stakeholders are not generalizable to all potential stakeholders but 

they provide illustrative examples. Appendix I provides additional 

information on our scope and methodology, appendix II lists the 

stakeholders we interviewed, and appendix III lists the studies we 

reviewed.

We conducted this performance audit from July 2011 to July 2012 in 

accordance with generally accepted government auditing standards. 

Those standards require that we plan and perform the audit to obtain 

sufficient, appropriate evidence to provide a reasonable basis for our 

findings and conclusions based on our audit objectives. We believe that 

the evidence obtained provides a reasonable basis for our findings and 

conclusions based on our audit objectives.

This section describes the role of coal in generating electricity, the four 

key EPA regulations, actions involved in maintaining electric reliability, 

and federal and state government roles in electricity markets.

Background 
 

Page 6 GAO-12-635 EPA Regulations and Electricity

Because of the abundance of coal and its historically low cost, many coalfueled 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,9 with a total 

316,800 megawatts (MW) of net summer generating capacity—about 30 

percent of the total generating capacity in the United States.10

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.

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.

 

9

Not all of these coal-fueled units would be subject to each of the four regulations. 

Additionally, noncoal electric generating units are subject to some of the regulations. Each 

regulation defines which units will be subject to it. For example, MATS applies to coal- and 

oil-fueled electricity utility steam generating units that have over 25 MW capacity and meet 

other requirements. We use the term electricity generating units rather than the specific 

regulatory definitions to refer to units subject to one or more regulation. 

10Generating capacity is measured in MW and refers to the maximum capability of a unit 

to produce electricity. A unit with 1,000 MW of capacity can generate up to 1,000 

megawatt-hours of electricity in 1 hour, enough to provide electricity for up to 1 million 

homes. 

Role of Coal in Electricity 

Generation
 

Page 7 GAO-12-635 EPA Regulations and Electricity

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.

Figure 1: Percentage of Electricity Generated from Coal by State, 2010
 

Page 8 GAO-12-635 EPA Regulations and Electricity

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.

Table 1: Major Milestones, Benefits and Costs of Four Key EPA Regulations

Regulation Date proposed Date finalized Compliance deadline 

EPA estimate of annualized 

benefits and costs (in billions 

2011 dollars)

CSAPR 

a

August 2010 August 2011 First phase was to begin in 2012 but is 

uncertain because of a court stay.

b $128-$299 in benefits and $0.9 

in costs

MATS

c 

May 2011 February 2012 April 2015 d

1-year extension (to April 2016) through 

permitting authorities possible

1 additional year possible through Clean Air 

Act Administrative Order (to April 2017)

$39-$96 in benefits and $10.2 

in costs

CCR 

c 

June 2010 No schedule for 

finalization

Depends on which option is finalized $0.09-$1.3 in benefits and $0.6-

$1.5 in costs, depending on 

which option is finalized

316(b)

e

April 2011 Scheduled

July 2012

As proposed, would be established on a caseby-case basis by permitting authorities up to 8 

years for impingement controls and 

entrainment controls anticipated to take longer

$0.02 in benefits and $0.4 in 

costs

Source: GAO analysis of EPA information.

Note: The proposed and finalized dates are the regulations' publication dates in the Federal Register, 

not the dates EPA signed the regulations and publicly released them. With the exception of CCR, the 

costs and benefits reflect actions taken by both coal-fueled units and other sources affected by the 

regulations. CCR would only apply to coal combustion residuals generated by coal-fueled units.

a

Cost and benefit estimates were converted to 2011 dollars using the gross domestic product deflator 

based on the calendar year. All estimates reflect a 3 percent discount rate except for CCR, where 

EPA used a 7 percent discount rate. EPA officials told us that it would be inappropriate to add 

together these estimates because of differences in baselines and analysis years. EPA did not provide

an estimate of the overall impact of the four regulations.

b

The regulation and its federal implementation plans have subsequently been amended. On 

December 30, 2011, a federal court stayed the regulation while it hears the case challenging the 

regulation finalized in August 2011. A lawsuit challenging one of the amendments has also been filed, 

but the court put it on hold while it considers the case challenging the August 2011 rulemaking.

c

EPA estimates of the costs and benefits of MATS and CSAPR refer to annualized costs and benefits 

in 2014 for CSAPR and 2016 for MATS.

d

Several lawsuits have been filed challenging MATS, but the court has not issued any decisions.

e

The Four Key EPA 

Regulations 

Reflects EPA’s estimate of costs and benefits assuming no change in the beneficial use of 

combustion residuals.
 

Page 9 GAO-12-635 EPA Regulations and Electricity

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 SO2, NOx, 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, SO2 and NOx emissions contribute to 

the formation of fine particulate matter, and NOx 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, 

SO2 and NOx 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.11

 

11EPA has set national ambient air quality standards for carbon monoxide, lead, NOx, 

ozone, particulate matter, and sulfur oxides. 

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 

Air Pollution: CSAPR and 

MATS
 

Page 10 GAO-12-635 EPA Regulations and Electricity

required to issue a federal implementation plan.12 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.13

In 2011, EPA finalized CSAPR and its federal implementation plans to 

replace the 2005 regulation and its federal implementation plans. 

Subsequently, EPA finalized amendments to the regulation and federal 

implementation plans and issued federal implementation plans for 

additional states. As amended, CSAPR would require emissions 

reductions in 28 states spanning much of the eastern half of the United 

States to address each state’s significant contribution to nonattainment 

and interference with maintenance of the air quality standards in 

downwind states.14

 

12States can replace federal implementation plans by developing and submitting for EPA 

approval state implementation plans that achieve the required amount of emissions 

reductions. 

(See fig. 2 for states that would be covered by 

CSAPR.) The reductions are to be achieved through the federal 

implementation plans that regulate certain electricity generating units by 

establishing SO2 and NOx trading programs. Under each trading program, 

covered states have SO2 and NOx emissions budgets and receive 

emissions allowances equal to the budget, which are distributed to power 

companies with generating units in that state. Each emissions allowance 

represents the right to emit 1 ton of SO2 or NOx. The allowances may be 

bought, sold, or banked for use in later years, but power companies must 

own enough allowances at the end of each control period to cover their 

emissions. Power companies with insufficient allowances at the end of 

13The 2005 regulation—known as the Clean Air Interstate Rule (CAIR)—requires 27 

states and the District of Columbia to adopt and submit revisions to their state 

implementation plans to eliminate SO2 and NOx 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.

14CSAPR would cover certain fossil fuel electricity generating units with over 25 MW 

capacity. 
 

Page 11 GAO-12-635 EPA Regulations and Electricity

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 SO2 emissions by 73 percent and NOx

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, 

2011.15

 

15A lawsuit challenging one of the amendments to CSPAR has also been filed, but the 

court put it on hold while it considers the case challenging the CSPAR regulation finalized 

in August 2011. 

Depending on how the court rules, CSAPR may change.
 

Page 12 GAO-12-635 EPA Regulations and Electricity

Figure 2: States Covered by CSAPR

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 
 

Page 13 GAO-12-635 EPA Regulations and Electricity

but did not issue a regulation under section 112.16 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 2012.17 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.18

 

16Specifically, the finding was regarding coal- and oil-fueled electric utility steam 

generating units. EPA also found that regulation of hazardous air pollutants emissions 

from natural gas-fueled electric utility steam generating units was not appropriate or 

necessary.

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 

17The statutory deadline for issuing section 112 regulations for hazardous air pollutants 

from coal- and oil-fueled electric utility steam generating units was 2 years from the date 

on which the units were listed as sources of hazardous air pollutants subject to regulation, 

which was December 20, 2000. In 2008, EPA settled a lawsuit alleging that it had failed to 

promulgate emissions standards under section 112 for hazardous air pollutants from coaland oil-fueled electric utility steam generating units by agreeing to sign a final regulation

by the end of 2011. 

18Specifically, MATS applies to electricity utility steam generating units that have over 25 

MW capacity and meet other requirements. MATS also establishes work practice 

standards in lieu of numerical emissions limitations for organic hazardous air pollutants 

and for limited use oil-fueled electric utility steam generating units as defined in the final 

regulation. 
 

Page 14 GAO-12-635 EPA Regulations and Electricity

year to come into compliance.19

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.

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.

20 EPA has stated 

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.21

The Resource Conservation and Recovery Act authorizes EPA to 

establish regulations for the treatment, storage, and disposal of 

hazardous waste and to establish national minimum criteria for the 

 

19EPA’s Office of Enforcement and Compliance Assurance issued a policy memorandum 

describing its intended approach regarding the use of Clean Air Act Section 113(a) 

administrative orders for sources that must operate in noncompliance with MATS for up to 

a year to address a specific and documented reliability concern. See: EPA, “The 

Environmental Protection Agency’s Enforcement Response Policy For Use of Clean Air 

Act Section 113(a) Administrative Orders in Relation To Electric Reliability and the 

Mercury and Air Toxics Standard” (available at 

http://www.epa.gov/compliance/resources/policies/civil/erp/mats-erp.pdf). 

20Some 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. 

21Furthermore, accidents—such as the 2008 breach of a dike at a Tennessee Valley 

Authority coal plant impoundment—can result in large-scale releases of coal combustion 

residuals. The 2008 accident caused the release of 5.4 million cubic yards of coal ash into 

a nearby river and covered more than 300 acres with coal ash; it also damaged homes, 

roads, rail lines, and utilities. 

Disposal of Coal Combustion 

Residuals: CCR 
 

Page 15 GAO-12-635 EPA Regulations and Electricity

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.22

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.23

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 

EPA does not have a schedule for 

issuing a final CCR regulation.

 

22The act exempted waste generated primarily from the combustion of coal or other fossil 

fuels—generally known as coal combustion residuals—from regulation as hazardous 

waste until EPA conducted a study and determined whether regulation as a hazardous 

waste was warranted. After issuing the required study (in two parts, the first in 1988 and 

the second in 1999), EPA determined in 1993, and again in 2000, that regulation of coal 

combustion residuals as a hazardous waste was unwarranted. 

23These estimates refer to EPA's scenario assuming CCR would not change the beneficial 

use of coal combustion residuals. EPA also estimated benefits for two other scenarios.

The scenario EPA considers to be the most likely assumes that CCR would increase 

beneficial use, and EPA estimated the annualized benefits of its special waste option 

would be $6,526 to $7,646 million and that the nonhazardous waste option would 

generate annualized benefits of $2,616 to $3,125 million. In a scenario where CCR 

decreases beneficial use, EPA estimated there would be negative annualized benefits for 

its special waste option (additional costs) of $17,270 to $16,149 million, and that the 

nonhazardous waste option would generate annualized benefits of $88 to $596 million.

Damage to Aquatic Life: 316(b)
 

Page 16 GAO-12-635 EPA Regulations and Electricity

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.24

Section 316(b) of the Clean Water Act requires EPA to establish 

standards for cooling water intake structures that reflect the best available 

technology for minimizing adverse environmental impact. To implement 

section 316(b), EPA has issued several regulations, including a regulation 

in 2004 that governed existing power plants with a large flow water 

intake.

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.

25

 

24Using water for cooling may also result in significant water use, and the discharge of 

cooling water that has been warmed from the plant process can raise the temperature of 

receiving water bodies. 

However, a federal appeals court struck down the 2004 

regulation. Following an appeal to the Supreme Court and settlement of 

other lawsuits related to the rulemaking, EPA proposed a regulation 

covering certain existing power plants and other facilities on April 20, 

2011. Regarding impingement, the proposal would establish fish mortality 

requirements reflecting the best available technology based on the 

performance of either (1) modified traveling screens—which capture and 

safely return fish to water bodies—or equivalent technology or (2) 

reduction of the facility’s water intake velocity—which would allow fish 

and other organisms to move away from the intake structure. Regarding 

entrainment, the proposal would require permitting authorities to follow a 

process prescribed in the regulation to determine compliance deadlines 

and the best available technology for entrainment controls on a sitespecific basis based on consideration of several specific factors. These 

factors include the quantified and qualitative social benefits and costs of 

available control options and impacts on electricity reliability. EPA 

estimates that approximately 45 percent of the nation’s generating 

25EPA 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.
 

Page 17 GAO-12-635 EPA Regulations and Electricity

capacity would be affected by the proposed regulation.26 As a result of 

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.

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.27

• 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.”

Reliability challenges can arise in 

multiple ways:

• 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 

 

26This proposed regulation applies to existing power generating and manufacturing 

facilities, as well as new units at existing facilities, which have a design intake flow of more

than 2 million gallons of water per day and use at least 25 percent of the water withdrawn 

exclusively for cooling purposes. The proposed regulation would also apply to oil-fueled, 

gas-fueled, and nuclear generating units that meet those requirements. EPA estimated 

that 559 fossil fuel electricity generating facilities would be subject to this regulation. 

27We use the term electricity grid to refer to an interconnected regional network of 

transmission lines and the term electricity system to refer to the electricity grid together 

with generating units used to provide electricity to customers. 

Planning and Day-to-Day 

Actions Involved in

Maintaining Electric 

Reliability
 

Page 18 GAO-12-635 EPA Regulations and Electricity

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).28

 

28Independent operators of the transmission system can be referred to as RTOs or 

Independent System Operators (ISO). RTOs and ISOs have similar functions, including 

operating the transmission system and longer-term regional planning, but ISOs tend to be 

smaller in geographic size or—for the ISOs in Texas and Canada—not subject to FERC 

jurisdiction over rates and tariffs. For the purposes of this report, we use the term RTOs to 

refer to both RTOs and ISOs.

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.
 

Page 19 GAO-12-635 EPA Regulations and Electricity

Figure 3: U.S. Regional Transmission Organizations

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 
 

Page 20 GAO-12-635 EPA Regulations and Electricity

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.

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.29

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.30 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.31

 

29Others involved in power company oversight may include municipal city councils for 

municipal power companies and boards of directors for cooperative power companies. 

30For the purposes of this report, we use “prices” to refer to the price of both wholesale 

and retail electricity consumed by businesses and households. Wholesale prices are 

generally determined in organized markets by the balance of supply and demand or may 

be negotiated directly between a seller and a buyer. Though FERC has a role in regulating 

wholesale prices for much of the electricity industry, it does not set wholesale prices or 

transmission rates charged by entities such as municipal utilities or most electric 

cooperatives. Furthermore, retail prices—also referred to as electricity rates—are 

generally determined by regulators, such as public utility commissions. FERC does not 

regulate or set retail electricity prices.

31The Public Utility Commission of Texas, rather than FERC, regulates the design and 

operation of the electricity markets in much of Texas. 

Federal and State 

Government Roles in 

Electricity Markets

Prices 
 

Page 21 GAO-12-635 EPA Regulations and Electricity

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.32 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.33

 

32Some RTOs have developed markets, called capacity markets, which provide them with 

information about what resources are expected to be available in the future so they can 

plan accordingly. For example power companies seeking to retire a generating unit in ISO 

New England—an RTO that operates in a six-state region in the Northeast—submit a 

retirement request during the forward capacity market 3 years in advance of their 

requested retirement date. According to ISO New England officials, the region does not 

have a separate retirement notification process for power companies. 

FERC conducts its 

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 

33According to FERC, RTOs have some authority to propose rule changes at FERC 

without broad stakeholder approval. 
 

Page 22 GAO-12-635 EPA Regulations and Electricity

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.34 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.35 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.36 Many electricity generating 

companies have received authority from FERC to sell power at marketbased 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.

 

34About 40 percent of the population lives in states and the District of Columbia that EIA 

classifies as having restructured their retail markets: Connecticut, Delaware, Illinois, 

Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, 

Ohio, Oregon, Pennsylvania, Rhode Island, and Texas. The remaining population lives in 

states that, according to EIA, have suspended their restructuring activities or have not 

restructured. We did not examine how EIA determined the status of restructuring in these 

states.

35Rates set by commissions may vary by customer classes (e.g., residential, commercial 

and industrial), as well as by the amount of electricity consumed.

36In addition to the market-determined generation component of their electric bill, 

consumers in these areas also pay a regulated rate for transmission and distribution.
 

Page 23 GAO-12-635 EPA Regulations and Electricity

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.37 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.38

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.

 

 

37For standards to be legally enforceable, FERC must approve them.

38See FERC "Policy Statement on the Commission's Role Regarding the Environmental 

Protection Agency's Mercury and Air Toxics Standards," Docket No. PL12-1-000 (May 17, 

2012).

Reliability
 

Page 24 GAO-12-635 EPA Regulations and Electricity

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 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.39

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 

 

39GAO has ongoing work on the views of stakeholders of factors that may affect the future 

use of coal to generate electricity. 

Power Companies Are 

Expected to Retrofit 

or Retire Units and 

Take Other Actions

It Is Uncertain How Power 

Companies Will Respond 

to Key EPA Regulations
 

Page 25 GAO-12-635 EPA Regulations and Electricity

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.40

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.

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.

41 These and other policies may contribute to generation from 

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 

dioxide emissions to address climate change.42

 

40U.S. Energy Information Administration, Short-Term Energy Outlook (May 2012). 

Such future requirements 

41These 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. 

42Under the terms of a settlement agreement, EPA was required to propose and finalize

new source performance standards for greenhouse gas emissions from existing electricity 

generating units. In April 2012, EPA proposed standards for certain new electricity 

generating units and stated that it would propose standards for existing units at an 

appropriate time.
 

Page 26 GAO-12-635 EPA Regulations and Electricity

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 2010.43

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 SO2 and acid gas emissions; (3) 

selective catalytic reduction or selective non-catalytic reduction units 

to control NOx; and (4) activated carbon injection units to reduce 

mercury emissions.44

 

43GAO, Air Emissions and Electricity Generation at U.S. Power Plants, 

Appendix IV describes these controls, how they 

operate, and the extent of their use among coal-fueled generating 

GAO-12-545R 

(Washington, D.C.: Apr. 18, 2012).

44Specifically, EPA projects that MATS will lead to the installation of fabric filters on an 

additional 102,000 MW of capacity; upgraded electrostatic precipitators on 34,000 MW; 

new dry sorbent injection units on 44,000 MW of; new scrubbers on 20,000 MW (and 

scrubber upgrades on 63,000 MW); and activated carbon injection units on 99,000 MW 

2015. EPA also projected that CSAPR will lead to retrofitted dry sorbent injection units on 

3,000 MW and scrubbers on 5,900 MW by 2014. NERC (2011) projected that 576 units 

with 234,371 MW of capacity would retrofit by the end of 2015. A study by staff of the 

Bipartisan Policy Center (which we refer to as Bipartisan Policy Center, 2011) projected, in 

2015, fabric filters on 516-541 units; dry sorbent injection units on 181-199 units (24,000 

MW of capacity); scrubbers on 84-85 units (51,000 MW); selective catalytic reduction units 

on 28-34 units; and activated carbon injection units on 368-392 units. (Full citations for 

selected studies are listed in app. III.)

Power Companies Are 

Expected to Retrofit Many

Generating Units, Retire 

Others, and Take 

Additional Actions
 

Page 27 GAO-12-635 EPA Regulations and Electricity

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.

45 These two studies projected that companies could 

convert 96-98 and 158 power plants to dry ash handling 

respectively.46 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.47 These projections 

are uncertain since the proposed regulation gives permitting 

authorities the responsibility to set entrainment requirements on a 

case-by-case basis.48 Figure 4 shows where some of these controls 

would be installed at a coal-fueled power plant.

 

45Coal combustion residuals can be gathered and transported with dry handling systems 

or with wet systems—such as when ash and water form a slurry that flows into an ash 

impoundment.

46See Bipartisan Policy Center (2011) and EPA-CCR (2010).

47See NERA (2011) and Bipartisan Policy Center (2011).

48Some researchers have observed that studies that examined the potential implications 

of the four key regulations that were conducted before EPA proposed 316(b) assumed 

that EPA would require closed-cycle cooling towers. While acknowledging that closedcycle cooling towers reduce impingement and entrainment mortality to the greatest extent, 

the proposed regulation concludes that it is not the best technology available for 

minimizing adverse environmental impacts on a national basis because of the following 

key factors: (1) potential adverse consequences to the reliability of energy delivery on the 

local level during the installation of cooling towers; (2) increased air emissions of various 

pollutants because of the additional fuel that would be burned to compensate for the 

energy required to operate the cooling towers and the slightly lower generating efficiency; 

(3) feasibility concerns and lack of land availability for placement of the cooling towers; 

and (4) the limited remaining useful life of some generating units. None of the study 

results that we cite here assumes that EPA would require closed-cycle cooling towers for 

all units.
 

Page 28 GAO-12-635 EPA Regulations and Electricity

Figure 4: Sample Layout of Controls at a Coal-Fueled Power Plant

Note: This figure is intended to be illustrative, though not exactly representative, of the controls used.

• Retire some units. Ten of the studies we reviewed include projections 

of how much coal-fueled capacity power companies might retire, with 

three of these studies reporting national projections corresponding to 

all four regulations. The projections in these three studies range from 

power companies retiring 2 to 12 percent of coal-fueled capacity in 
 

Page 29 GAO-12-635 EPA Regulations and Electricity

response to the four regulations rather than installing controls.49 Some 

regions may see more significant levels of retirements. For example, a 

study by the Midwest Independent Transmission System Operator, 

Inc. (MISO), an RTO that covers all or parts of 11 U.S. states and a 

Canadian province, projected that 18 percent of the coal-fueled 

capacity in the U.S. portion of its region could retire. EPA and some 

stakeholders we interviewed pointed out that some of these projected 

retirements may have occurred at some point even without the new 

regulations. As discussed previously, several industry trends may be 

contributing to the retirement of coal-fueled generating units, including 

relatively low natural gas prices, increasing prices for coal, and low 

expected growth in demand for electricity. For example, officials at an 

investment analysis firm highlighted a financial analysis they had 

conducted that found that 7 to 11 percent of coal-fueled capacity may 

not be economic to operate in 2012 to 2014 at expected coal and 

natural gas prices.50 This capacity could be at risk of retirement 

unless economic conditions change. In addition, one of the studies we 

reviewed found that changes in expectations regarding future natural 

gas prices and electricity demand have an impact on projected 

retirements that is comparable to the effect of CSAPR and MATS.51

 

49See North American Electric Reliability Corporation (2011), Bipartisan Policy Center 

(2011), and NERA (2011). EPA expressed concerns about some of the NERA study's

assumptions and said its modeling was not sufficiently transparent. Power companies are 

planning to retire generating units in the absence of the four regulations, but the 

projections we cite here attempted to distinguish retirements in response to the 

regulations from those that would occur in their absence. 

At 

the same time, some stakeholders told us that the regulations may 

accelerate retirements because power companies may not want to 

invest in controls for units they expect to retire soon for other reasons. 

Several stakeholders highlighted that the units power companies may 

retire early are likely to be smaller, older, and less efficient units. 

Consistent with stakeholder views about the regulations accelerating 

retirements, power companies have announced their plans to retire 

units representing about 9 percent of coal-fueled capacity with the 

bulk of these retirements occurring by MATS’s 2015 compliance 

50Hugh Wynne, et al. “Bernstein Commodities and Power: The Forward Prices for Coal 

and Gas Can’t Both Be Right—How Utilities Will Arbitrage Fuel Prices in 2012” (Dec. 16, 

2011). 

51See RFF (2012). 
 

Page 30 GAO-12-635 EPA Regulations and Electricity

deadline.52

Figure 5: Capacity of Actual and Planned Coal-Fueled Generating Unit Retirements, 1990-2020

(See fig. 5.) These planned retirements include 

retirements for any reason, including in response to the four 

regulations, and would correspond to almost twice as much coalfueled capacity as retired in the 22 years from 1990 through April 

2012.

Note: Data on generating unit capacity refers to units with over 25 MW of net summer capacity—the 

generating unit’s capacity to produce electricity during the summer when electricity demand for many 

electricity systems and losses in efficiency are generally the highest. Net capacity figures exclude 

output used internally for plant operations.

• Other actions. The studies we reviewed cited several other actions 

that power companies may take in response to the new regulations, 

including building new generating units, upgrading transmission 

 

52Information on planned retirements reflect publicly reported plans as identified by 

Ventyx. As plans may change, actual future retirements may differ from these plans. 
 

Page 31 GAO-12-635 EPA Regulations and Electricity

systems to ensure reliability, and changing how they operate their 

units. First, several of the studies we reviewed project that power 

companies may increasingly use natural gas to produce electricity as 

they retire coal-fueled units and because remaining coal units may 

become somewhat more expensive to operate. Increased generation 

from natural gas could come from a combination of existing natural 

gas units being used more often and new natural gas units being built. 

Second, power companies may also upgrade transmission systems to 

address reliability issues that arise due to units’ retirements, which 

may include relatively straightforward incremental upgrades to 

existing transformers or circuit breakers, as well as more significant 

enhancements such as new transmission lines. Third, EPA projects 

that power companies may also change how they operate their 

universe of generating units in response to the regulations. This is 

particularly likely in response to CSAPR, which would give power 

companies flexibility in deciding how to meet emissions limitations, 

including by running more polluting units less often or purchasing 

emissions allowances.

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.

Actions Taken by 

Power Companies 

Will Likely Increase 

Electricity Prices and 

May Contribute to 

Reliability Challenges 

in Some Regions
 

Page 32 GAO-12-635 EPA Regulations and Electricity

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.53 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).54 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.55 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.56

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 

 

 

53Specifically, the Bipartisan Policy Center study projected annualized costs of $16 billion 

in 2015 and $20 billion in 2025. NERA Economic Consulting estimated additional annual 

costs of $21 billion on average over the 2012-2020 period, with a total net present value of 

$130 billion. EPA expressed concerns about some of the NERA study's assumptions and 

said its modeling was not sufficiently transparent. It is important to note that these studies 

made different assumptions about the regulations that can affect their findings. For 

example, while EPA has stated that it expects power companies to comply with 316(b) 

over a 15-year period from 2013-2027, NERA assumed costs were incurred in 2015. 

NERA's assumption may overstate costs. At the same time, both NERA and the Bipartisan 

Policy Center’s analysis assumed that EPA would finalize the solid waste option for CCR. 

Costs may be higher if EPA instead finalizes the special waste option.

54EPA officials said that it would be inappropriate to add together its cost estimates from 

these regulations because of differences in baselines and analysis years. EPA did not 

provide an estimate of the overall impact of the four regulations. 

55EPA, Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, 

EPA#430R10010 (Washington, D.C.: August 2010) 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html) and EPA, 

Documentation Supplement for EPA Base Case v4.10_PTox-Updates for Proposed 

Toxics Rule, EPA#430-R-11-006 (Washington, D.C.: March 2011) 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf).

56These costs do not include costs that may be associated with retrofitting or upgrading 

particulate matter controls that may be needed for dry sorbent or activated carbon 

injection units.

Estimated Costs of Power 

Companies’ Actions in 

Response to Four EPA 

Regulations 
 

Page 33 GAO-12-635 EPA Regulations and Electricity

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.

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.57 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.58 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.59

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 

 

57DOE, Resource Adequacy Implications of Forthcoming EPA Air Quality Regulations 

(December 2011). 

58EPA’s analysis examined the overall capacity of the industry to design, supply, and 

install equipment but did not examine the availability of specific resources or when retrofit 

projects may begin. EPA found that, given past experience deploying controls and building 

new generating capacity, sufficient engineering and other capacity would be available to 

meet these needs. See: EPA, An Assessment of the Feasibility of Retrofits for the Mercury 

and Air Toxics Standards Rule (Dec. 16, 2011).

59Modularization and prefabrication refers to assembling individual components of 

complex controls off-site and combining and attaching these assemblies to the generating 

unit to reduce on-site construction times.

Some Actions May Be 

Challenging to Complete 

by Compliance Deadlines
 

Page 34 GAO-12-635 EPA Regulations and Electricity

completed by the 2016 deadline, with the 1-year extension available from 

permitting authorities.60

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:

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.

• Regulatory approvals can take time. Retrofits, transmission line 

upgrades, and construction of new generating units will require 

 

60The analysis assessed the rate at which fabric filters can be deployed for MATS 

compliance, assuming fabric filters may be required on 533 generating units representing 

166,000 MW of capacity. See: Utility Air Regulatory Group, Attachments to the Comments 

of the Utility Air Regulatory Group, Volume 4, Docket EPA-HQ-OAR-2009-0234, 

(Washington, D.C.: Aug. 4, 2011).
 

Page 35 GAO-12-635 EPA Regulations and Electricity

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.61 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 startup, but some may extend completion times.62

• 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.

 

61The construction of new generating units and certain retrofits on existing units may 

require various types of air permits. For example, power companies may need to go 

through New Source Review, a preconstruction permitting process that establishes 

emissions limits and requires the use of certain emissions control technologies. Power 

plants will only need a major New Source Review permit if the retrofit is a major 

modification—a physical or operational change that would result in a significant net 

increase in emissions of a regulated pollutant—which is determined on a case-by-case 

basis. States may require minor New Source Review permits for retrofits that are not 

major modifications. 

62An examination of over 100 recent preconstruction pollution control retrofit approvals 

before public utility commissions in 10 states found that the average approval time across 

all cases was 7 months, though it took over a year for six cases. M.J. Bradley & 

Associates LLC, “Public Utility Commission Study,” Prepared for SRA International, Mar. 

31, 2011.
 

Page 36 GAO-12-635 EPA Regulations and Electricity

Figure 6: Installation of a Scrubber at the Cardinal Plant in Brilliant, Ohio

• 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 
 

Page 37 GAO-12-635 EPA Regulations and Electricity

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.

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.63 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.64

 

63These 18 states are Colorado, Connecticut, Delaware, Georgia, Illinois, Maryland, 

Massachusetts, Michigan, Minnesota, Montana, New Hampshire, New Jersey, New 

Mexico, New York, North Carolina, Oregon, Utah, and Wisconsin. 

In contrast, other 

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.

64Under the New Source Review provisions of the Clean Air Act, generating units built 

after August 7, 1977 must obtain a preconstruction permit that establishes emission limits 

and requires the use of certain pollution control technologies. See GAO-12-545R. 

Impacts Are Expected to 

Vary Across the Country
 

Page 38 GAO-12-635 EPA Regulations and Electricity

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),65 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.66 Electricity prices are influenced by a 

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.

 

65RFF is a nonprofit and nonpartisan organization that conducts independent research on 

environmental, energy, natural resource and environmental health issues. 

66EPA officials told us that it would be inappropriate to add together its price increase 

estimates from these regulations because of differences in baselines and analysis years. 

EPA did not prepare an estimate of the overall impact of the four regulations. 

Actions Would Likely 

Increase Electricity Prices 

in Some Regions
 

Page 39 GAO-12-635 EPA Regulations and Electricity

Table 2: EPA Estimates of Potential Average National and Regional Retail Electricity 

Price Increases Due to Compliance with Four Key EPA Regulations 

Regulation

Range of estimated 

regional price increases

Estimated national 

average price increase

CSAPRa -0.2-3.1% 0.8%

MATS 1.3-6.3% a 3.1%

316(b) 0.0- 0.4% 0.1%

CCR–Solid Waste Option 0.0-1.2% 0.2%

CCR–Special Waste Option 0.0-5.6% 0.8%

Source: GAO analysis of EPA information.

Note: Estimates refer to impacts for different years—2014 for CSAPR, 2015 for MATS and 316(b), 

and incremental regulatory costs compared with electricity prices in 2009 for CCR.

a

NERA examined all four regulations and estimated that average electricity 

prices from 2012 to 2020 may be only slightly affected in the Northwest 

(0.1 percent increase), although they could increase by an average 13.5 

percent in Kentucky and Tennessee—states more dependent on 

electricity generated from coal.

Estimates are for regions in the contiguous United States.

67 The RFF study examined the combined 

impact of MATS and CSAPR and projected a 0.6 percent increase in 

electricity prices in 2020. The RFF study also estimated that other factors, 

including falling natural gas prices and other trends, may be contributing 

to declining future electricity prices that may offset some or all of the price 

increases due to the EPA regulations.68

Electricity prices may increase because the investments associated with 

the actions power companies take to respond to the EPA regulations, and 

any increases in the costs of generating electricity, would be passed on to 

customers to varying extents. In traditionally regulated markets, power 

companies would submit rate cases to their public utility commissions 

MISO looked at the price 

implications of all four regulations in its region, projecting a 7 to 7.6 

percent retail price increase.

 

67EPA expressed concerns about some of the NERA study's assumptions and said its 

modeling was not sufficiently transparent. 

68While EIA’s study does not estimate the impact of the EPA regulations on prices, it 

projects that average retail electricity prices may decline from 9.8 cents per kilowatt-hour 

in 2010 to 9.2 cents per kilowatt-hour in 2019, in part due to declines in the prices of 

natural gas. 
 

Page 40 GAO-12-635 EPA Regulations and Electricity

requesting approval to increase prices to cover costs associated with 

responding to the regulations. If a state public utility commission finds 

these costs are prudent, prices would be increased accordingly to recover 

these costs. For example, the public utility commission in Kentucky 

approved environmental compliance plans for two power companies to 

install controls and convert to dry ash handling related to CSAPR, MATS, 

and CCR, among other actions.69

Likewise, other investments to address any potential reliability challenges 

could also increase prices. For example, as a power company retires 

generating units, the relevant system planner identifies whether the 

retirements would cause reliability challenges. If there are reliability 

The public utility commission of 

Kentucky stated that these plans may increase residential electricity bills 

by 18 percent for one company and by 10 percent for another—about $16 

and $7 per month for an average customer, respectively, by 2016. 

However, increased costs may not be fully passed on to consumers in 

restructured markets where generating units are not owned by a stateregulated utility. This could occur because prices paid for electricity 

generation are set by FERC-overseen competitive markets. In these 

instances, power companies, rather than consumers, may absorb some, 

or all, of these costs. In such markets, power companies bid to provide 

electricity at a certain price. These bids are accepted from lowest to 

highest until all demand for electricity is met. The price of the last bid 

accepted to meet demand generally establishes the market price. If this 

price-setting bid is from a coal-fueled unit that is more expensive to 

operate because of controls or from a unit that is more expensive to 

operate than a retired coal-fueled unit, electricity prices are likely to rise. If 

the price-setting bid is from a generating unit that is not affected by the 

regulations and that would have set the price in the absence of the 

regulations, then prices are likely to remain the same.

 

69The approved plans also include other changes that affect price implications of these 

investments, such as a reduction in the rate of return the companies may earn on their 

investments and a 1 cent increase in a monthly charge to fund a home energy assistance 

program. See: Commonwealth of Kentucky Public Service Commission, "PSC Accepts 

Settlement in KU and LG&E Environmental Compliance Cases," (Frankfort, KY: Dec. 15, 

2011); Commonwealth of Kentucky Public Service Commission, "Order: Application of 

Kentucky Utilities Company for Certificates of Public Convenience and Necessity and 

Approval of its 2011 Compliance Plan for Recovery by Environmental Surcharge," Case 

No. 2011-00161; and Commonwealth of Kentucky Public Service Commission, "Order: 

Application of Louisville Gas and Electric Company for Certificates of Public Convenience 

and Necessity and Approval of its 2011 Compliance Plan for Recovery by Environmental 

Surcharge," Case No. 2011-00162.
 

Page 41 GAO-12-635 EPA Regulations and Electricity

challenges, the system planner would identify actions to mitigate the 

challenge, and costs incurred to build or acquire new generating capacity 

or to upgrade transmission systems could result in costs to consumers. In 

general, costs associated with transmission system upgrades would be 

passed on to consumers through regulated prices.

The actions power companies take in response to the four key EPA 

regulations are not likely to cause widespread reliability challenges, 

according to the high-level studies we reviewed. Four of the studies we 

reviewed and an analysis by DOE assessed resource adequacy, one 

aspect of reliability, by analyzing regional reserve margins––high-level 

comparisons of projected electricity demand to the projected capacity—

after taking into account potential increases in retirements and other 

changes associated with the EPA regulations. These analyses show how 

much flexibility there is for power companies to meet peak demand and

serve as an important high-level indicator of one aspect of reliability.70 In 

general, the studies found that capacity is expected to continue to exceed 

demand by the amount needed to maintain resource adequacy, in some 

cases substantially. However, in one study, the reserve margins of Texas 

and New England are projected to fall below levels needed by 2015 

according to some metrics.71

 

70Electricity demand varies significantly with the time of day and year, generally reaching 

its peak, or highest levels on hot summer afternoons. As demand grows, power 

companies increase output from the generating units already supplying electricity and 

begin generating electricity at additional units as needed to meet the rising levels of 

demand. The last units used to meet rising demand, so-called “peak demand” units, are 

generally much more expensive to operate and operate the equivalent of only a few days 

per year. As a result, the costs of generating electricity can vary dramatically, becoming 

more expensive during periods of peak demand than during periods of average demand.

Narrow reserve margins in Texas and New 

England are generally expected regardless of actions associated with the 

EPA regulations and may be attributed to a number of factors such as 

electricity demand growth exceeding electricity generating capacity. 

Officials from the system planner in New England told us that they expect 

to have sufficient capacity available. They noted that at least some of the 

study results may not have taken into account mechanisms in their region 

to ensure sufficient capacity is available in the future.

71NERC (2011).

Actions May Not Cause 

Widespread Reliability 

Concerns but May 

Contribute to Challenges 

in Some Areas
 

Page 42 GAO-12-635 EPA Regulations and Electricity

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.
 

Page 43 GAO-12-635 EPA Regulations and Electricity

Figure 7: Location and Capacity of Planned Coal-Fueled Generating Unit Retrofits and Retirements through 2020, as of 

April 9, 2012

Note: Planned retrofits include units with planned SO2, NOx, particulate matter, or mercury controls. 

Includes units with over 25 MW of net summer capacity—the generating unit’s capacity to produce 

electricity during the summer when electricity demand for many electricity systems and losses in 

efficiency are generally the highest. Net capacity figures exclude output used internally for plant 

operations.

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.)
 

Page 44 GAO-12-635 EPA Regulations and Electricity

• 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.72

• 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 

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.

 

72Power companies take generating units off-line for regularly scheduled maintenance that 

often lasts about 4 weeks.
 

Page 45 GAO-12-635 EPA Regulations and Electricity

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.73 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.74

• 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 

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.

 

73States served by PJM include all or parts of Delaware, District of Columbia, Indiana, 

Illinois, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, 

Tennessee, Virginia, and West Virginia.

74See PJM, “Future Deactivations (as of May 30, 2012),” 

http://pjm.com/planning/generation-retirements/gr-summaries.aspx. In many cases, it may 

be possible for these units to retire before 2016 without affecting reliability if, for example, 

new demand response or substitute generation can be put in place or if operational 

changes can be used while permanent solutions are developed.
 

Page 46 GAO-12-635 EPA Regulations and Electricity

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.

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.

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 

Existing Tools Could 

Mitigate Many 

Adverse Implications, 

but Agencies Do Not 

Have a Formal 

Process to Monitor 

Industry Progress 

Toward Compliance

Available Tools May Help 

Mitigate Some, but Not All, 

Price Increases
 

Page 47 GAO-12-635 EPA Regulations and Electricity

new units, entering into long-term power contracts, or other steps.75 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.76

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 wellfunctioning 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 

 

75There is considerable variation in the tools employed by state public utility commissions 

to oversee the electricity industry. For example, integrated resource planning, generally a 

feature of traditionally regulated markets, is not uniformly used in all traditionally regulated 

states and may also be used in restructured states. 

76Georgia Power Company also sought approval for initial expenditures related to the 

installation of fabric filters on some of its units. The Georgia commission approved 

expenditures associated with the initiation of construction of the fabric filters and required 

monthly compliance reports on the fabric filter installations until the matter can be 

reconsidered in Georgia Power’s 2013 Integrated Resource Plan.
 

Page 48 GAO-12-635 EPA Regulations and Electricity

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.77

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 

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.

 

77According to EPA’s estimates of the proposed CSAPR regulation, allowing allowance 

trading may lower the costs of achieving emission levels required by CSAPR by over 23 

percent compared to a scenario where each generating unit is required to meet its own 

emissions targets.
 

Page 49 GAO-12-635 EPA Regulations and Electricity

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.78 In response to our 

recommendation, FERC has taken steps to facilitate broader use of 

demand-response programs among RTOs.

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 

 

78GAO, Electricity Markets: Consumers Could Benefit from Demand Programs, but 

Challenges Remain, GAO-04-844 (Washington D.C.: Aug. 13, 2004).

Available Tools Could 

Address Many, but Not All, 

Reliability Challenges
 

Page 50 GAO-12-635 EPA Regulations and Electricity

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. 79

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.

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.

Six additional tools exist that, according to multiple stakeholders, can be 

used to address such actual reliability challenges that arise. These tools 

are: (1) Clean Air Act section 112 1-year extensions, (2) Clean Air Act 

administrative orders, (3) Clean Air Act consent decrees, (4) reliabilitymust-run agreements, (5) DOE emergency authority, and (6) Clean Air 

Act section 112 presidential exemption authority. However, while these 

 

79If the actions power companies take in response to the four EPA regulations violate 

NERC standards, FERC or NERC may take enforcement action, such as requiring a 

mitigation plan to come into compliance or levying penalties against the power companies, 

to ensure that reliability is not compromised. 
 

Page 51 GAO-12-635 EPA Regulations and Electricity

tools are likely to address many reliability challenges arising after the 

compliance deadlines, as discussed below, there are limitations to using 

them, which contribute to uncertainty about their collective breadth and 

applicability as a backstop for addressing all reliability challenges.

• Clean Air Act section 112 1-year extensions.80 This extension of the 

compliance deadline is a tool through which companies may obtain up 

to an additional year to comply with MATS if needed for the 

installation of controls.81

• Clean Air Act administrative orders.

According to the final MATS regulation’s 

preamble, these extensions should be broadly available to enable 

power companies to install controls, and permitting authorities—

generally states and local authorities— will have the discretion to use 

this authority to address a range of situations. For example, according 

to EPA, it may be reasonable for permitting authorities to grant an 

extension to a unit slated for retirement if its continued operation is 

needed to maintain reliability while another unit installs emissions 

controls. An official from one permitting authority we spoke to said, 

pending executive management approval, its organization plans to

adopt EPA’s interpretation of when to grant extensions even though 

this interpretation departs from EPA’s and its long-standing 

interpretation of “installation of controls.” However, two stakeholders 

raised concerns about the certainty of receiving this 1-year extension, 

with one stakeholder questioning whether permitting authorities would 

approve extensions for generating units that are retiring rather than 

installing controls.

82

 

80The extensions are authorized by section 112(i)(3)(B) of the Clean Air Act. 

Clean Air Act administrative 

orders are another tool through which reliability challenges resulting 

from actions to comply with relevant regulations, for example, MATS, 

may be addressed. Where necessary to avoid a serious risk to electric 

reliability, and when certain requirements are met, EPA intends to 

issue administrative orders to bring a generating unit that is required 

to run for reliability purposes into compliance with MATS within 1 

81Because the statute limits the extension to 1 year, this tool will not fully address 

situations in which units need more than 4 years to comply.

82These 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.
 

Page 52 GAO-12-635 EPA Regulations and Electricity

year.83 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.84

• Clean Air Act consent decrees.

In addition, this tool would not 

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.

85

 

83This policy is described in the EPA MATS enforcement memo, formally titled “The 

Environmental Protection Agency’s Enforcement Response Policy For Use of Clean Air 

Act Section 113(a) Administrative Orders in Relation To Electric Reliability and the 

Mercury and Air Toxics Standard” (the “MATS Enforcement Policy”), which is available at 

http://www.epa.gov/compliance/resources/policies/civil/erp/mats-erp.pdf.

Consent decrees are another tool 

that EPA can use to address situations where a reliability critical unit 

needs additional time to respond to the regulations. In this context, 

consent decrees are agreements between the federal government––

the Department of Justice, in cooperation with EPA––and power 

companies that generally establish a schedule for bringing a power 

company’s generating units into compliance with an EPA regulation 

and typically impose a civil penalty on power companies. According to 

EPA officials, because these agreements require negotiation and 

must be filed with a federal court, they can take a year or more to 

develop. Therefore, a consent decree may only be effective for 

resolving a reliability challenge if EPA has sufficient advance time to 

84According to EPA officials and two stakeholders, provided that EPA establishes a welldocumented record supporting its decision to issue an administrative order, the risk of a 

successful citizens’ suit can be minimized. 

85These consent decrees are authorized by section 113(b) of the Clean Air Act.
 

Page 53 GAO-12-635 EPA Regulations and Electricity

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 mustrun 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.86

 

86Specifically, the Susquehanna-Roseland transmission line was being developed to 

avoid potential reliability violations including some associated with Hudson 1’s potential 

retirement. According to representatives from PJM, permitting issues have significantly 

delayed the project.

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 
 

Page 54 GAO-12-635 EPA Regulations and Electricity

noncompliance.87

• 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.88

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 

However, DOE officials explained that, in situations 

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.

 

87In the case of CSAPR, the cost of allowances purchased by a power company to 

operate its units could be incorporated into applicable reliability must-run agreements. 

However, for the reasons described above, an RMR might be less applicable under 

CSAPR if sufficient allowances were not available for purchase. 

88Not all of these orders were for the generation of electricity. 
 

Page 55 GAO-12-635 EPA Regulations and Electricity

laws and regulations.89

• 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.

Representatives from two power companies 

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 timeconsuming 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.

90

 

89Furthermore, a power company operating under a section 202(c) order may have limited 

options when addressing certain circumstances at a power plant that could result in 

violations of environmental laws or regulations. For example, if a generating unit’s 

environmental controls malfunction or fail unexpectedly, a power company operating 

under a section 202(c) order may not be able to take action, such as reducing operation, 

to avoid violating federal or state environmental laws or regulations. If a violation occurs, 

the power company may be subject to enforcement action or lawsuits brought by private 

parties.

90An exemption under this subsection may be extended for one or more additional 

periods, each period not to exceed 2 years. The President must report to Congress on 

each exemption or extension of an exemption made. 
 

Page 56 GAO-12-635 EPA Regulations and Electricity

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.
 

Page 57 GAO-12-635 EPA Regulations and Electricity

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,91 and 

FERC and state public utility regulators have established a forum to 

explore reliability challenges related to the EPA regulations.92

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 

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. 

 

91See FERC, "Technical Conference to Discuss Policy Issues Related to Reliability of the 

Bulk Power System," AD12-1-000, (Washington, D.C.: Nov. 29-30, 2011) 

http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=6053&CalType=%20&Calendar

ID=116&Date=&View=Listview. 

92Specifically, FERC and the National Association of Regulatory Utility Commissioners, a 

national organization representing State public service commissioners, established a 

forum on reliability and the environment that first met on February 7, 2012. The next 

meeting is scheduled for July 25, 2012.

Agencies Have Begun 

Taking Steps to Monitor 

Industry’s Progress but 

Have Not Documented 

Their Process, and FERC 

Has Not Proactively

Reviewed RTO Rules
 

Page 58 GAO-12-635 EPA Regulations and Electricity

is essential in ensuring that a risk management approach is current and 

relevant.93 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.94 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.95

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 

 

93GAO, Risk Management: Further Refinements Needed to Assess Risks and Prioritize 

Protective Measures at Ports and Other Critical Infrastructure, GAO-06-91 (Washington, 

D.C.: Dec. 15, 2005). Risk management is a strategy for helping policymakers make 

decisions about assessing risks, allocating resources, and taking actions under conditions 

of uncertainty.

94Some system planners—including power companies and RTOs—and state regulators 

have begun collecting information that may relate to these topics.

95FERC officials said they believe they will have adequate staff to address most of these 

responsibilities. However, they agreed that a larger than expected number of local 

reliability challenges could make it difficult for them to review the reliability impacts of units 

whose owners request an administrative order from EPA. FERC recently issued a policy 

statement explaining the process it intends to use to provide timely advice to EPA on 

requests for administrative orders.
 

Page 59 GAO-12-635 EPA Regulations and Electricity

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.96

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 

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.

 

96GAO, Live Animal Imports: Agencies Need Better Collaboration to Reduce the Risk of 

Animal-Related Diseases, GAO-11-9 (Washington, D.C.: Nov. 8, 2010); GAO, National 

Security: Key Challenges and Solutions to Strengthen Interagency Collaboration, 

GAO-10-822T (Washington, D.C.: June 9, 2010); GAO, Homeland Defense: U.S. Northern 

Command Has Made Progress but Needs to Address Force Allocation, Readiness 

Tracking Gaps, and Other Issues, GAO-08-251 (Washington, D.C.: Apr. 16, 2008).
 

Page 60 GAO-12-635 EPA Regulations and Electricity

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. 
 

Page 61 GAO-12-635 EPA Regulations and Electricity

Table 3: Selected Concerns about RTO Market Rules Arising from the EPA Regulations and Other Industry Factors

Region Concern about RTO market rule Potential change and status

ERCOT The Electric Reliability Council of Texas (ERCOT) manages the 

transmission of electricity for most of Texas and does not always 

have authority to deny outages that may adversely impact reliability.

a Modify outage rules so ERCOT can deny 

outages that pose reliability challenges. (Concern 

identified)

MISO Power companies in the MISO region may not have full information 

about the reliability and cost implications of retiring a particular 

generating unit. 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. For 

example, if a power company learned that the cost of actions to 

offset the retirement of a reliability-critical generating unit were more 

expensive than installing pollution controls, it might choose to install 

controls rather than retire the unit. 

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. 

(Under discussion)

MISO Because they have comparatively shorter start-up times than coal 

plants, certain natural gas plants have historically provided “quick 

start” capacity for addressing short-term capacity shortages. 

However, because the EPA regulations increase the costs of using 

coal relative to natural gas for electricity production, and because of 

recent lower natural gas prices, natural gas plants previously used 

as quick start capacity may be used more routinely, which could limit 

their availability to provide quick start capacity. 

Modify market rules to encourage the 

development of additional “quick-start” capacity. 

(Under discussion) 

MISO Power companies are required to notify MISO 26 weeks before 

retiring generating units. Because some options to address potential 

reliability challenges can take several years, such as building a large 

transmission line, not having timely information about all planned 

retirements could limit the options available to MISO and increase 

the costs of mitigating these challenges. However, earlier notification 

than 26 weeks may not be practical since power companies may not 

know their plans that far in advance.

Keep MISO’s notification time frame at 26 weeks, 

but make other modifications to MISO’s process 

for receiving and evaluating notifications of 

pending retirements, including allowing for 

nonbinding retirement requests. (Under 

discussion)

ISO New 

England 

In ISO New England, the transmission planning process and 

resource adequacy markets are not as well-aligned as possible. As 

a result, concerns about resource adequacy and local reliability may 

be addressed less efficiently and with higher costs.

Take steps to better align resource adequacy 

markets with the transmission planning 

processes. This proposed change was prompted 

by multiple events, including environmental 

compliance costs associated with EPA 

regulations and the economics of fuel prices. 

According to an ISO New England document, the 

RTO expects these proposed changes to better 

address reliability needs and mitigate cost 

increases. (Under discussion) 

PJM PJM’s transmission planning process did not include an analysis of 

“at-risk” generation or possible future scenarios that are as 

extensive as the RTO would like.

Revise PJM’s transmission planning process to 

allow it to better manage uncertainty about “atrisk” generation due to changes in environmental 

regulations, among other things. The change 

included clarifying that PJM can consider 

proposed public policy initiatives in its planning 

analyses. (Conditionally accepted by FERC)

Sources: GAO analysis of RTO documents, discussions with RTO officials, and other sources.

a

The Public Utility Commission of Texas, rather than FERC, regulates the design and operation of the 

electricity markets in the ERCOT region.
 

Page 62 GAO-12-635 EPA Regulations and Electricity

FERC officials told us that initial discussions with the RTOs—such as 

through the FERC technical conference—indicated that current market 

rules are adequate and that FERC will review any proposed changes to 

market rules that they receive from RTOs to ensure that the rules 

continue to promote just and reasonable rates and, where relevant, 

address reliability issues. However, the commission does not have plans 

to proactively assess the adequacy of any rules unless RTOs propose 

specific changes. Furthermore, FERC officials said the commission does 

not plan to evaluate whether changes proposed by one RTO may also be 

useful at others. FERC officials said they have also not assessed the 

rules of non-RTO system planners because FERC has more limited 

authority over non-RTO rules. However, FERC officials acknowledged 

that they have the authority to proactively request that RTOs make 

changes to rules if FERC believes a rule change is warranted. Under the 

current approach—wherein individual RTOs consider potential changes 

and request approval from FERC—FERC risks taking a piecemeal 

approach to oversight and may miss opportunities to encourage 

development of market rules in all regions that are adequately designed 

to promote just and reasonable rates in the context of the industry’s 

transition.

The four key EPA regulations—two finalized and two proposed—would 

reduce adverse health or environmental impacts associated with coalfueled 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 

Conclusions 
 

Page 63 GAO-12-635 EPA Regulations and Electricity

whether existing tools are adequate or additional tools are needed. 

FERC, DOE, and EPA have taken important first steps to coordinate with 

RTOs, other system planners, and state regulators, among others, to 

better understand these issues. However, without a formal, documented 

process that the three agencies have agreed upon for jointly, routinely 

monitoring industry’s progress, it is uncertain whether their activities will 

be sufficiently comprehensive and fully leverage their unique areas of 

expertise. FERC, DOE, and EPA can build on their initial monitoring 

efforts by documenting their process for monitoring, including the 

expected frequency of their contact, and how they will organize their 

efforts and share information. Moreover, as shown by multiple hearings 

and the introduction of legislation that would affect some or all of the 

regulations, there has been congressional interest in the potential 

reliability and price implications of these regulations. Information from a 

coordinated monitoring effort could help inform these ongoing 

deliberations and make clear whether additional statutory authority is 

needed to cost-effectively address any reliability challenges that actually 

arise.

In addition, rules at system planners, including RTO market rules and, in 

some cases, similar rules at non-RTO system planners, govern such 

details as how these entities schedule temporary shutdowns for retrofits; 

receive notification from power companies regarding retirements of 

generating units; and address potential reliability challenges, including 

how transmission upgrades and demand-response are considered and 

pursued. These rules matter greatly in terms of whether potential 

reliability challenges are managed as cost-effectively as possible. FERC 

has not proactively evaluated whether RTO rules will be adequate to 

ensure timely, cost-effective mitigation of potential reliability challenges 

associated with multiple generating unit retirements and shutdowns, 

which may occur over a short period in light of the EPA regulations. As a 

result, FERC may miss opportunities to encourage development of rules 

in all regions that are adequately designed to promote just and 

reasonable rates in the context of the industry’s transition.

We are making the following two recommendations:

• To further strengthen agency efforts to understand whether existing 

tools are adequate, or additional tools are needed, we recommend 

that the Chairman of FERC, the Secretary of Energy, and the 

Administrator of the EPA develop and document a formal, joint 

process consistent with each agencies’ respective statutory 

authorities to monitor industry’s progress in responding to the EPA 

Recommendations for 

Executive Action
 

Page 64 GAO-12-635 EPA Regulations and Electricity

regulations until at least 2017. Each agency, to the extent practical, 

should leverage resources and share the results of its efforts with the 

other agencies. The agencies should consider providing Congress 

with the results of their monitoring efforts, including whether additional 

statutory authority is needed to address any potential adverse 

implications.

• To ensure that RTO market rules and, to the extent practical, similar 

rules at non-RTO system planners promote timely, cost-effective 

mitigation of potential reliability challenges associated with the EPA 

regulations reviewed in this report, we recommend that the Chairman 

of FERC assess the adequacy of existing rules for this purpose. In 

particular, this assessment should cover rules related to scheduling 

retrofits, retirement notification, and whether more can be done to 

facilitate demand response. If the FERC Chairman determines that 

these rules are not adequate, FERC should consider requesting that 

these entities make changes where appropriate.

We provided a draft of this report to FERC, DOE, and EPA for comment. 

In written comments, which are reproduced in appendixes V through VII, 

DOE and EPA agreed with the recommendation directed to them, and 

FERC disagreed with both recommendations directed to it. 

Regarding our first recommendation that FERC, DOE, and EPA develop 

and document a formal process to monitor industry's progress in 

responding to the EPA regulations, DOE and EPA generally agreed. 

FERC disagreed with the recommendation, stating that we did not take 

into account a number of actions FERC has taken, including publicly 

committing to work closely with industry, states, and other agencies to 

address issues that arise. FERC cited several examples of the actions it 

has taken, and we made some clarifying changes and, in one case, 

added language about an example that we had not previously included in 

the report. FERC also stated that it had taken further steps to implement 

our recommendation after seeing our draft report. We agree that FERC 

has taken positive steps, and we are encouraged that FERC has begun 

to implement our recommendations. However, we do not believe these 

actions adequately represent the type of formal, documented process 

needed for EPA, DOE, and FERC to monitor industry's progress in 

responding to the regulations. FERC also said that, as an independent 

agency, it cannot dictate the sharing of information with and by other 

parts of the government. We acknowledge there may be limits on the 

extent to which the three agencies can collaborate and clarified our 

recommendation accordingly. All three agencies noted that they are 

Agency Comments

and Our Evaluation
 

Page 65 GAO-12-635 EPA Regulations and Electricity

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. 
 

Page 66 GAO-12-635 EPA Regulations and Electricity

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.

Sincerely yours,

Frank Rusco

Director, Natural Resources and Environment

David C. Trimble

Director, Natural Resources and Environment
Appendix I: Scope and Methodology

Page 67 GAO-12-635 EPA Regulations and Electricity

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.

Appendix I: Scope and Methodology
Appendix I: Scope and Methodology

Page 68 GAO-12-635 EPA Regulations and Electricity

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 
Appendix I: Scope and Methodology

Page 69 GAO-12-635 EPA Regulations and Electricity

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

Page 70 GAO-12-635 EPA Regulations and Electricity

1. Department of Energy

2. Environmental Protection Agency

3. Federal Energy Regulatory Commission

4. Georgia

5. Kentucky

6. Missouri

7. Ohio

8. Pennsylvania

9. Texas

10. Electric Reliability Council of Texas

11. ISO New England

12. Midwest Independent Transmission System Operator

13. New York Independent System Operator

14. PJM Interconnection

15. Southwest Power Pool

16. American Electric Power

17. Big Rivers Electric Corporation

18. Calpine

 

1

With the exception of Kentucky, Missouri, and Pennsylvania, we spoke with both 

electricity and environmental regulators in these states.

Appendix II: List of Stakeholders

Federal Agencies

State Electricity and 

Environmental Regulators1

Regional Transmission 

Organizations

Power Companies
Appendix II: List of Stakeholders

Page 71 GAO-12-635 EPA Regulations and Electricity

19. City Utilities of Springfield

20. Exelon Corporation

21. First Energy

22. GenOn Energy

23. Southern Company

24. Tennessee Valley Authority

25. Alstom

26. Bernstein Research

27. Clean Air Task Force

28. FBR Capital Markets

29. International Brotherhood of Electrical Workers

30. North American Electric Reliability Corporation

31. Potomac Economics

32. Prof. Henry Jacoby, Massachusetts Institute of Technology Sloan 

School of Management

33. Susan Tierney, The Analysis Group

Other
Appendix III: List of Studies

Page 72 GAO-12-635 EPA Regulations and Electricity

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-R11-003. 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.

Appendix III: List of Studies
Appendix III: List of Studies

Page 73 GAO-12-635 EPA Regulations and Electricity

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 CoalFueled Electricity Generating Units

Page 74 GAO-12-635 EPA Regulations and Electricity

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.

Figure 8: Capacity and Share of Total Capacity from Coal-Fueled Electricity Generating Units by Region, as of April 9, 2012

Appendix IV: Additional Information on 

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

Page 75 GAO-12-635 EPA Regulations and Electricity

Note: Capacity is in megawatts and includes units with over 25 megawatts of net summer capacity—

the generating unit’s capacity to produce electricity during the summer when electricity demand for 

many electricity systems and losses in efficiency are generally the highest. Net capacity figures 

exclude output used internally for plant operations.

a

The combined area of SERC Reliability Corporation and Southwest Power Pool Regional Entity 

refers to overlapping regional area boundaries. For example, some generating unit owners participate 

in one region and their associated transmission system owner in another. Generating unit capacity is 

accounted for in the region where the generation owner participates.

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 (SO2) and acid gas 

emissions.
Appendix IV: Additional Information on CoalFueled Electricity Generating Units

Page 76 GAO-12-635 EPA Regulations and Electricity

Table 4: Summary of Air Pollution Control Equipment Used at Coal-Fueled Electricity Generating Units

Primary pollutant 

targeted Equipment name How it works Removal efficiency

Particulate matter Electrostatic precipitator a An induced electrical charge removes particles 

from flue gas.

99.5% 

Fabric filter (commonly referred 

to as a “baghouse”)

Flue gas passes through tightly woven fabric 

filter “bags” that filter out the particulates. 

99.9% 

SO2 and other acid 

gases

Flue gas desulfurization unit 

(commonly referred to as a 

“scrubber”) 

b Wet flue gas desulfurization units inject a 

liquid sorbent, such as limestone, into the flue 

gas to form a wet solid that can be disposed of 

or sold.

Dry flue gas desulfurization units inject a dry 

sorbent, such as lime, into the flue gas to form 

a solid byproduct that is collected.

Wet scrubbers – 99% 

removal of SO

Dry scrubbers – 95% 

removal of SO

2

2

Dry sorbent injection unit An alkaline powdered material is injected into 

the flue gas (postcombustion) to react with the 

SO2

50% with an electrostatic 

precipitator, 75% with a 

and other acid gases. The resulting fabric filter 

product is then collected through a particulate 

matter control device.

Nitrogen oxides 

(NOx

Combustion control technologies, 

) such as low-NOx burners

Coal combustion conditions are adjusted so 

less NO c x

45% reduction in the 

is formed. formation of NOx

Post-combustion controls, such 

as selective catalytic reduction 

(SCR) and selective non-catalytic 

reduction (SNCR) units

SCRs inject ammonia into flue gas to form

nitrogen and water and use a catalyst to 

enhance the reaction.

SNCRs inject ammonia into flue gas to react 

with NOx

SCRs – 95% removal of 

NO

as well but do not use a catalyst.

SNCRs –75% removal of 

NO

x

Mercury

x

Activated carbon injection units d Activated carbon is injected into flue gas, 

binds with mercury, and is collected in a 

particulate matter control device.

At least 90% with a 

fabric filter

Sources: GAO summary of reports by EPA, EIA, National Academies, Electric Power Research Institute, and industry documents.

Note: Removal efficiency figures refer to the highest capacity to remove listed pollutants. Units may 

not always achieve these removal rates.

a

The MATS regulation specifically places limits on “filterable” particulate matter.

b

Another approach to reducing SO2, mercury, and acid gas emissions from generating units is to 

switch from using coals with higher contents of these substances to coals with lower contents, or to 

blend coals.

c

Low-NOx burners may also be used in conjunction with postcombustion controls for NOx . 

d

Figure 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.

Mercury can be removed through various controls. For example, wet scrubbers remove mercury, and 

particulate matter control equipment can remove mercury that is bound to the ash.
Appendix IV: Additional Information on CoalFueled Electricity Generating Units

Page 77 GAO-12-635 EPA Regulations and Electricity

Figure 9: Capacity of Coal-Fueled Generating Units Retrofitted with Select Air Pollution Controls, 2000-2011

Note: Capacity is in thousand megawatts and includes units with over 25 megawatts of net summer 

capacity—the generating unit’s capacity to produce electricity during the summer when electricity 

demand for many electricity systems and losses in efficiency are generally the highest. Net capacity 

figures exclude output used internally for plant operations.

a

Scrubbers include wet, dry, and other types of units.
Appendix IV: Additional Information on CoalFueled Electricity Generating Units

Page 78 GAO-12-635 EPA Regulations and Electricity

Figure 10: Percentage of Coal-Fueled Generating Capacity with Air Pollution Controls Installed by Region, as of April 9, 2012
Appendix IV: Additional Information on CoalFueled Electricity Generating Units

Page 79 GAO-12-635 EPA Regulations and Electricity

Note: Includes units with over 25 MW of net summer capacity—the generating unit’s capacity to 

produce electricity during the summer when electricity demand for many electricity systems and 

losses in efficiency are generally the highest. Net capacity figures exclude output used internally for 

plant operations.

a

In addition, one unit with 85 MW capacity, 0.3 percent of the region’s coal-fueled capacity, has a 

different mercury-specific control.
Appendix IV: Additional Information on CoalFueled Electricity Generating Units

Page 80 GAO-12-635 EPA Regulations and Electricity

Figure 11: Percentage of Coal-Fueled Generating Capacity with Air Pollution Controls Installed by Region, as of April 9, 2012
Appendix IV: Additional Information on CoalFueled Electricity Generating Units

Page 81 GAO-12-635 EPA Regulations and Electricity

Note: Includes units with over 25 MW of net summer capacity—the generating unit’s capacity to 

produce electricity during the summer when electricity demand for many electricity systems and 

losses in efficiency are generally the highest. Net capacity figures exclude output used internally for 

plant operations.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 82 GAO-12-635 EPA Regulations and Electricity

Appendix V: Comments from the Federal 

Energy Regulatory Commission

Note: GAO comments 

supplementing those in 

the report text appear at 

the end of this appendix.

See comment 1.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 83 GAO-12-635 EPA Regulations and Electricity

See comment 3.

See comment 2.

See comment 1.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 84 GAO-12-635 EPA Regulations and Electricity

See comment 5.

See comment 4.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 85 GAO-12-635 EPA Regulations and Electricity

See comment 6.

See comment 5.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 86 GAO-12-635 EPA Regulations and Electricity

See comment 7.

See comment 6.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 87 GAO-12-635 EPA Regulations and Electricity

See comment 10.

See comment 9.

See comment 8.
Appendix V: Comments from the Federal 

Energy Regulatory Commission

Page 88 GAO-12-635 EPA Regulations and Electricity
Appendix V: Comments from the 

Federal Energy Regulatory 

Commission

Page 89 GAO-12-635 EPA Regulations and Electricity

The following are GAO's comments on the Federal Energy Regulatory 

Commission's letter dated July 3, 2012.

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 

GAO Comments
Appendix V: Comments from the 

Federal Energy Regulatory 

Commission

Page 90 GAO-12-635 EPA Regulations and Electricity

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 
Appendix V: Comments from the 

Federal Energy Regulatory 

Commission

Page 91 GAO-12-635 EPA Regulations and Electricity

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 mustrun 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

Page 92 GAO-12-635 EPA Regulations and Electricity

Appendix VI: Comments from the 

Department of Energy
Appendix VI: Comments from the Department 

of Energy

Page 93 GAO-12-635 EPA Regulations and Electricity
Appendix VII: Comments from the 

Environmental Protection Agency

Page 94 GAO-12-635 EPA Regulations and Electricity

Appendix VII: Comments from the 

Environmental Protection Agency
Appendix VII: Comments from the 

Environmental Protection Agency

Page 95 GAO-12-635 EPA Regulations and Electricity
Appendix VII: Comments from the 

Environmental Protection Agency

Page 96 GAO-12-635 EPA Regulations and Electricity
Appendix VII: Comments from the 

Environmental Protection Agency

Page 97 GAO-12-635 EPA Regulations and Electricity
Appendix VII: Comments from the 

Environmental Protection Agency

Page 98 GAO-12-635 EPA Regulations and Electricity
Appendix VIII: GAO Contacts 

and Staff Acknowledgments

Page 99 GAO-12-635 EPA Regulations and Electricity

Frank Rusco, (202) 512-3841 or ruscof@gao.gov

David C. Trimble, (202) 512-3841 or trimbled@gao.gov

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.

Appendix VIII: GAO Contacts and Staff 

Acknowledgments 

GAO Contacts

Staff 

Acknowledgments 

(361308)
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