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United States Government Accountability Office: 
GAO: 

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: 

GAO-12-635: 

GAO Highlights: 

Highlights of GAO-12-635, a report to the Chairman, Committee on 
Commerce, Science, and Transportation, U.S. Senate. 

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 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. 

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. 

View [hyperlink, http://www.gao.gov/products/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. 

[End of section] 

Contents: 

Letter: 

Background: 

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

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

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

Conclusions: 

Recommendations for Executive Action: 

Agency Comments and Our Evaluation: 

Appendix I: Scope and Methodology: 

Appendix II: List of Stakeholders: 

Appendix III: List of Studies: 

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

Appendix V: Comments from the Federal Energy Regulatory Commission: 

Appendix VI: Comments from the Department of Energy: 

Appendix VII: Comments from the Environmental Protection Agency: 

Appendix VIII: GAO Contacts and Staff Acknowledgments: 

Tables: 

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

Table 2: EPA Estimates of Potential Average National and Regional 
Retail Electricity Price Increases Due to Compliance with Four Key EPA 
Regulations: 

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

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

Figures: 

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

Figure 2: States Covered by CSAPR: 

Figure 3: U.S. Regional Transmission Organizations: 

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

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

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

Figure 7: Location and Capacity of Planned Coal-Fueled Generating Unit 
Retrofits and Retirements through 2020, as of April 9, 2012: 

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

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

Figure 10: Percentage of Coal-Fueled Generating Capacity with Air 
Pollution Controls Installed by Region, as of April 9, 2012: 

Figure 11: Percentage of Coal-Fueled Generating Capacity with Air 
Pollution Controls Installed by Region, as of April 9, 2012: 

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: nitrogen oxides: 

PJM: PJM Interconnection: 

RFF: Resources for the Future: 

RTO: Regional Transmission Organization: 

SCR: selective catalytic reduction unit: 

SNCR: selective non-catalytic reduction unit: 

SO2: sulfur dioxide: 

[End of section] 

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

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.[Footnote 3] 

These four regulations could also have significant implications for 
the electricity industry. Generating units fueled by coal--which 
comprise a large portion of the national electricity supply--are 
expected to be affected by the four proposed regulations. Power 
companies might retrofit some generating units with controls to reduce 
pollutants[Footnote 4] and, when it is not economic to retrofit, may 
retire some generating units, according to EPA.[Footnote 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.[Footnote 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 of electricity to 
consumers.[Footnote 7] 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. 

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

To examine what available information indicates about actions power 
companies may take in response to these regulations and their 
potential market and reliability implications, we (1) selected for 
review 12 studies of companies' projected responses to the regulations 
and the potential impacts of these responses and (2) analyzed data 
from Ventyx Velocity Suite on electricity generating units. We 
considered several factors in selecting studies, including how closely 
they reflect the four regulations, and we assessed the reasonableness 
of the studies' assumptions and methodologies. The studies we selected 
were carried out by EPA, the Energy Information Administration (EIA), 
system planners, research organizations, and a consulting firm. 
[Footnote 8] 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 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. 

Background: 

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

Role of Coal in Electricity Generation: 

Because of the abundance of coal and its historically low cost, many 
coal-fueled electricity generating units were built and these provide 
a large share of the electricity produced in the United States. In 
2010, there were 1,396 coal-fueled generating units in the United 
States,[Footnote 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.[Footnote 10] In addition to coal, electricity is 
produced by burning other fossil fuels, particularly natural gas and 
oil; using nuclear power through nuclear fission; and using renewable 
sources, including hydropower, wind, geothermal, and solar. 

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

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

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

[Refer to PDF for image: illustrated U.S. map] 

Percentage of electricity generated from coal: 0-20%; 
Alaska: 
California: 
Connecticut: 
Hawaii: 
Idaho: 
Maine: 
Massachusetts: 
Nevada: 
New Hampshire: 
New Jersey: 
New York: 
Oregon: 
Rhode Island: 
Vermont: 
Washington: 

Percentage of electricity generated from coal: 20-50%; 
Alabama: 
Arkansas: 
Arizona: 
Florida: 
Louisiana: 
Mississippi: 
Oklahoma: 
Pennsylvania: 
South Carolina: 
South Dakota: 
Texas: 
Virginia: 

Percentage of electricity generated from coal: 50-70%; 
Colorado: 
Delaware: 
Illinois: 
Kansas: 
Michigan: 
Minnesota: 
Montana: 
Nebraska: 
North Carolina: 
Tennessee: 
Wisconsin: 

Percentage of electricity generated from coal: Greater than 70%; 
District of Columbia: 
Georgia: 
Indiana: 
Iowa: 
Kentucky: 
Maryland: 
Missouri: 
New Mexico: 
North Dakota: 
Ohio: 
Utah: 
West Virginia: 
Wyoming: 

Source: GAO analysis of EIA data; Map REsources (map). 

[End of figure] 

The Four Key EPA Regulations: 

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: CSAPR; 
Date proposed: August 2010; 
Date finalized: August 2011[B]; 
Compliance deadline: First phase was to begin in 2012 but is uncertain 
because of a court stay; 
EPA estimate of annualized benefits and costs (in billions 2011 
dollars)[A]: $128-$299 in benefits and $0.9 in costs[C]. 

Regulation: MATS; 
Date proposed: May 2011; 
Date finalized: February 2012[D]; 
Compliance deadline: April 2015; 
1-year extension (to April 2016) through permitting authorities 
possible; 
1 additional year possible through Clean Air Act Administrative Order 
(to April 2017); 
EPA estimate of annualized benefits and costs (in billions 2011 
dollars)[A]: $39-$96 in benefits and $10.2 in costs[C]. 

Regulation: CCR; 
Date proposed: June 2010; 
Date finalized: No schedule for finalization; 
Compliance deadline: Depends on which option is finalized; 
EPA estimate of annualized benefits and costs (in billions 2011 
dollars)[A]: $0.09-$1.3 in benefits and $0.6-$1.5 in costs, depending 
on which option is finalized[E]. 

Regulation: 316(b); 
Date proposed: April 2011; 
Date finalized: Scheduled; 
July 2012; 
Compliance deadline: As proposed, would be established on a case-by-
case basis by permitting authorities up to 8 years for impingement 
controls and entrainment controls anticipated to take longer; 
EPA estimate of annualized benefits and costs (in billions 2011 
dollars)[A]: $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] Reflects EPA's estimate of costs and benefits assuming no change 
in the beneficial use of combustion residuals. 

[End of table] 

Air Pollution: CSAPR and MATS: 

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. 
[Footnote 11] States generally develop state implementation plans that 
detail how the standards will be attained and maintained. In addition, 
the act's Good Neighbor provision requires state implementation plans 
to prohibit emissions of air pollutants in amounts that will 
contribute significantly to nonattainment or interference with 
maintenance of a national ambient air quality standard in any other 
state. Electricity generating units contribute to pollution that 
affects the ability of downwind states to attain and maintain these 
standards because some of these pollutants may travel in the 
atmosphere hundreds or thousands of miles from the areas where they 
originate. If a state fails to develop and submit a state 
implementation plan that satisfies all Clean Air Act requirements, 
including the Good Neighbor provision, by specified deadlines, EPA is 
required to issue a federal implementation plan.[Footnote 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.[Footnote 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.[Footnote 14] (See figure 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 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.[Footnote 15] Depending on how the court rules, CSAPR may 
change. 

Figure 2: States Covered by CSAPR: 

[Refer to PDF for image: illustrated U.S. map] 

States not covered by CSAPR: 
Arizona: 
California: 
Colorado: 
Connecticut: 
Delaware: 
District of Columbia: 
Idaho: 
Maine: 
Massachusetts: 
Montana: 
Nevada: 
New Hampshire: 
New Mexico: 
North Dakota: 
Oregon: 
Rhode Island: 
South Dakota: 
Utah: 
Vermont: 
Washington: 
Wyoming: 

States controlled for fine particles only (annual SO2 and NO,) (3 
states): 
Kansas: 
Minnesota: 
Nebraska: 

States controlled for ozone only (ozone season NON) (5 states): 
Arkansas: 
Florida: 
Louisiana: 
Mississippi: 
Oklahoma: 

States controlled for both fine particles (annual SO2 and NOx) and 
ozone (ozone season NOx) (20 states): 
Alabama:
Georgia: 
Illinois: 
Indiana: 
Iowa: 
Kentucky: 
Maryland: 
Michigan: 
Missouri: 
New Jersey: 
New York: 
North Carolina: 
Ohio: 
Pennsylvania: 
South Carolina: 
Tennessee: 
Texas: 
Virginia: 
West Virginia: 
Wisconsin: 

Sources: EPA; Map Resources (map). 

[End of figure] 

The Clean Air Act also requires EPA to study the public health hazards 
from electricity generating units' emissions of mercury and other 
hazardous air pollutants and to regulate those emissions under section 
112 if it finds that such regulation is "appropriate and necessary." 
EPA made such a finding regarding certain electricity generating units 
in 2000 but did not issue a regulation under section 112.[Footnote 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. 
[Footnote 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.[Footnote 18] Generating units would have 3 years, until April 
2015, to comply with MATS and could receive up to a 1-year extension 
from permitting authorities (typically state or local authorities), if 
necessary for the installation of controls. EPA also outlined a 
mechanism to allow units that are needed to address specific and 
documented reliability concerns to receive Clean Air Act 
administrative orders to provide up to an additional year to come into 
compliance.[Footnote 19] 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. 

Disposal of Coal Combustion Residuals: CCR: 

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.[Footnote 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.[Footnote 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 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.[Footnote 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.[Footnote 23] EPA does not have a schedule 
for issuing a final CCR regulation. 

Damage to Aquatic Life: 316(b): 

Coal and other types of electricity generating units often draw in 
large volumes of water from nearby rivers, lakes, or oceans to use for 
cooling, which can damage aquatic life. Thermoelectric generating 
units are the largest water use category by sector, using 201 billion 
gallons per day in 2005, the most recent year for which data were 
available. Depending on how a generating unit's cooling system is 
designed, drawing in water for cooling can result in fish and other 
aquatic life being impinged--trapped--against intake screens used to 
filter out solid matter, as well as entrained--drawn into--the 
generating unit with the cooling water.[Footnote 24] 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. 

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.[Footnote 25] 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 site-specific 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 capacity would be affected by the proposed 
regulation.[Footnote 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. 

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

Electric reliability refers to the ability to meet the needs of end-
use customers even when unexpected generating equipment failures or 
other factors affect the electricity system.[Footnote 27] Reliability 
challenges can arise in multiple ways: 

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

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

* or by changing power flows on the transmission system in order to 
maintain suitable operating conditions. 

System planners attempt to avoid reliability problems through advance 
planning of transmission and, in some cases, generation resources. The 
role of a system planner can be carried out by individual power 
companies or regional entities called Regional Transmission 
Organizations (RTO).[Footnote 28] 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. 

Figure 3: U.S. Regional Transmission Organizations: 

[Refer to PDF for image: illustrated U.S. map] 

California ISO (CAISO); 
Electric Reliability Council of Texas (ERGOT); 
Southwest Power Pool (SPP); 
Midwest Independent Transmission System Operator (MISO); 
PJM Interconnection (PJM); 
New York ISO (NYISO); 
ISO New England (ISO-NE). 

Sources: FERC; Map Resources (map). 

[End of figure] 

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

Federal and State Government Roles in Electricity Markets: 

The potential impact of retrofits and retirements on electricity 
prices and reliability is generally overseen by the federal regulator, 
FERC; state regulators, including state public utility commissions; 
and others.[Footnote 29] 

Prices: 

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.[Footnote 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.[Footnote 31] 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.[Footnote 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.[Footnote 33] 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 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. 
[Footnote 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.[Footnote 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.[Footnote 36] Many 
electricity generating companies have received authority from FERC to 
sell power at market-based rates and, in restructured markets, these 
companies would aim to recover the costs of any investments made to 
comply with EPA regulations through wholesale sales of electricity, 
but their ability to do so depends on overall supply and demand 
conditions, which determine the prices they can receive. 

Reliability: 

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.[Footnote 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.[Footnote 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. 

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

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

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

It is unclear how power companies will respond to the four key EPA 
regulations, in part because there is uncertainty about the 
regulations themselves and other factors affecting the industry, 
including future natural gas prices. Analysts that have studied how 
power companies may respond to the regulations have made different 
assumptions regarding these factors, which affect power companies' 
assessments of whether to make additional investments in coal-fueled 
generating units such as investments that may be needed to respond to 
the four key regulations.[Footnote 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 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.[Footnote 
40] However, some stakeholders we interviewed raised concerns about 
the prospects for continued low natural gas prices, citing the 
potential increased future use of natural gas for electricity or more 
strict regulation of natural gas production that could affect the long-
term outlook for domestic natural gas production and prices. 

Another factor that contributes to uncertainty is the increased focus 
on renewable energy production and other potential future regulations. 
In recent years, there have been federal and state efforts to 
encourage the development of renewable energy sources--particularly 
wind and solar--to produce electricity. For example, 30 states have 
laws or regulations requiring power companies to increasingly rely on 
renewable sources for electricity.[Footnote 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.[Footnote 42] Such future 
requirements 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.[Footnote 43] 

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

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

* Retrofit many coal-fueled generating units. All 12 of the studies we 
reviewed suggest that power companies may retrofit many coal-fueled 
generating units with new or upgraded controls to respond to the four 
key regulations. EPA's analyses and two other studies we reviewed 
report national projections of how companies may reduce emissions of 
air pollutants to meet the finalized MATS and CSAPR requirements. 
Projections in these studies suggest that one-third to three-quarters 
of all coal-fueled capacity could be retrofitted or upgraded with some 
combination of controls, including the following: (1) fabric filters 
or electrostatic precipitators to control particulate matter; (2) dry 
sorbent injection or flue gas desulfurization units--also known as 
scrubbers--to control 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.[Footnote 44] Appendix IV describes these controls, 
how they operate, and the extent of their use among coal-fueled 
generating units. Two of the studies we reviewed include estimates of 
how power companies may respond to CCR, projecting that some companies 
would convert power plants from wet ash handling to dry ash handling, 
which uses conveyor belts or trucks to gather and transport coal 
combustion residuals to storage sites, since wet ash impoundments may 
effectively be phased out under the final CCR regulation.[Footnote 45] 
These two studies projected that companies could convert 96-98 and 158 
power plants to dry ash handling respectively.[Footnote 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.[Footnote 47] These projections are uncertain since the 
proposed regulation gives permitting authorities the responsibility to 
set entrainment requirements on a case-by-case basis.[Footnote 48] 
Figure 4 shows where some of these controls would be installed at a 
coal-fueled power plant. 

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

[Refer to PDF for image: illustration] 

Depicted on the illustration: 

Coal supply; 
Stack; 
SCR or SNCR; 
Fly ash; 
Fabric filter or ESP; 
FGD; 
FGD byproducts; 
ACI or DSI; 
Boiler; 
Turbine and generator; 
Electricity; 
Cooling tower; 
Intake screens; 
Cool water; 
River; 
Coal combustion residuals for disposal or reuse; 
Impoundment or landfill. 
      
Legend: 
ACI = activated carbon injection unit. 
DSI = dry sorbent injection unit. 
ESP = electrostatic precipitator. 
FGD = flue gas desulfurization unit. 
SCR = selective catalytic reduction unit. 
SNCR = selective non-catalytic reduction unit. 

Sources: GAO analysis of information from Electric Power Research 
Institute, Tennessee Valley Authority, and Babcock & Wilcox. 

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

[End of figure] 

* 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 response to the four regulations rather than 
installing controls.[Footnote 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.[Footnote 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.[Footnote 51] 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 deadline.[Footnote 52] (See figure 5.) These planned 
retirements include retirements for any reason, including in response 
to the four regulations, and would correspond to almost twice as much 
coal-fueled capacity as retired in the 22 years from 1990 through 
April 2012. 

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

[Refer to PDF for image: vertical bar graph] 

 Actual Planned 

Year: 1990; 
Actual: 65 megawatts. 

Year: 1991; 
Actual: 549 megawatts. 

Year: 1992; 
Actual: 220 megawatts. 

Year: 1993; 
Actual: 376 megawatts. 

Year: 1994; 
Actual: 691 megawatts. 

Year: 1995; 
Actual: 175 megawatts. 

Year: 1996; 
Actual: 0 megawatts. 

Year: 1997; 
Actual: 224 megawatts. 

Year: 1998; 
Actual: 0 megawatts. 

Year: 1999; 
Actual: 279 megawatts. 

Year: 2000; 
Actual: 336 megawatts. 

Year: 2001; 
Actual: 72 megawatts. 

Year: 2002; 
Actual: 546 megawatts. 

Year: 2003; 
Actual: 1,076 megawatts. 

Year: 2004; 
Actual: 299 megawatts. 

Year: 2005; 
Actual: 581 megawatts. 

Year: 2006; 
Actual: 487 megawatts. 

Year: 2007; 
Actual: 1,083 megawatts. 

Year: 2008; 
Actual: 656 megawatts. 

Year: 2009; 
Actual: 2,023 megawatts. 

Year: 2010; 
Actual: 1,630 megawatts. 

Year: 2011; 
Actual: 2,149 megawatts. 

Year: 2012; 
Actual: 1,589 megawatts;
Planned: 8,227 megawatts. 

Year: 2013; 
Planned: 1,617 megawatts. 

Year: 2014; 
Planned: 3,515 megawatts. 

Year: 2015; 
Planned: 9,883 megawatts. 

Year: 2016; 
Planned: 79 megawatts. 

Year: 2017; 
Planned: 2,569 megawatts. 

Year: 2018; 
Planned: 741 megawatts. 

Year: 2019; 
Planned: 670 megawatts. 

Year: 2020; 
Planned: 1,454 megawatts. 

Source: GAO analysis of Ventyx data. 

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. 

[End of figure] 

* 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 
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. 

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

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

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

Two of the studies we reviewed reported national estimates of the 
total costs of actions power companies may take in response to the 
four key EPA regulations, projecting from $16 billion to $21 billion 
in additional annual costs.[Footnote 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).[Footnote 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.[Footnote 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. 
[Footnote 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 region to offset capacity lost from unit retirements could cost 
from $2 billion to $10 billion and that an additional $580 to $880 
million in transmission upgrades could be required to maintain 
reliability criteria after potential unit retirements in net present 
value terms. MISO's study is the only one we identified that estimated 
potential transmission investments needed to maintain reliability. 

Some Actions May Be Challenging to Complete by Compliance Deadlines: 

Assessments by EPA and DOE suggest that much of the electricity 
industry may be able to complete actions by the compliance deadlines. 
In their assessments, EPA and DOE compared past coal-fueled generating 
unit retrofits to the MATS compliance deadline. DOE found that, 
assuming prompt action by regulators and generators, the timelines 
associated with retrofits and new construction are generally 
comparable to EPA's regulatory deadlines.[Footnote 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.[Footnote 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.[Footnote 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 completed by the 2016 deadline, with the 1-year extension 
available from permitting authorities.[Footnote 60] EPA's study of the 
final MATS regulation indicates that fewer fabric filters may be 
needed than were assumed by the Utility Air Regulatory Group, and the 
group's results suggest that it may be possible to complete these by 
the 2016 deadline with the 1-year extension. Similarly, actions to 
mitigate capacity loss and other challenges due to generating unit 
retirements could take time as they could involve building new 
generating units or upgrading transmission systems. If these actions 
cannot be completed before compliance deadlines, a reliability 
challenge could arise unless steps are taken to keep generating units 
that are critical for the reliability of the electricity system from 
retiring. There have been examples of efforts to conduct transmission 
upgrades to address reliability challenges that have taken longer than 
the 4 years that may be available to meet the MATS compliance deadline 
assuming a 1-year extension. For example, transmission upgrades were 
necessary to allow several generating units with total capacity of 790 
MW to retire at the Benning Road and Buzzard Point power plants on the 
Potomac Electric Power Company system, which serves 788,000 customers 
in Maryland and the District of Columbia. In 2007, the plants' owner 
notified the system planner of its desire to retire the units by mid-
2012. The needed transmission upgrades, including new transformers and 
circuits, are expected to be completed in mid-2012. 

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

* Regulatory approvals can take time. Retrofits, transmission line 
upgrades, and construction of new generating units will require 
various state and local regulatory approvals, which may include 
construction permits and modifications of air pollution permits, which 
can extend the completion time of such projects.[Footnote 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 start-
up, but some may extend completion times.[Footnote 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. 

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

[Refer to PDF for image: 2 photographs] 

Depicted in photographs: 

Cooling tower; 
Scrubber; 
Ductwork to connect scrubber to tower; 
Boilers; 
Selective catalytic reduction unit. 

Source: American Electric Power Company; copyright 2011 American 
Electric Power Company, Inc. 

[End of figure] 

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

Impacts Are Expected to Vary Across the Country: 

The actions power companies take to respond to the four EPA 
regulations are expected to affect some parts of the country less than 
others. First, some areas of the country, such as California, 
Washington, Oregon, and Maine, have little coal-fueled generation and, 
therefore, are expected to see little impact. In addition, CSAPR would 
cover 28 states in the eastern half of the United States, so 
generating units in the remaining states would not be affected. 
Second, power companies in certain areas may have already installed 
some of the needed controls on their coal-fueled units for a variety 
of reasons. For example, at least 18 states have enacted laws or 
regulations to limit mercury emissions from electricity 
generation.[Footnote 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.[Footnote 64] 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. 

Actions Would Likely Increase Electricity Prices in Some Regions: 

The actions power companies may take in response to the four key EPA 
regulations would likely increase electricity prices in some regions. 
Of the 12 studies we reviewed, EPA and three other entities--Resources 
for the Future (RFF),[Footnote 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.[Footnote 
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. 

Table 2: EPA Estimates of Potential Average National and Regional 
Retail Electricity Price Increases Due to Compliance with Four Key EPA 
Regulations: 

Regulation: CSAPR[A]; 
Range of estimated regional price increases: -0.2-3.1%; 
Estimated national average price increase: 0.8%. 

Regulation: MATS[A]; 
Range of estimated regional price increases: 1.3-6.3%; 
Estimated national average price increase: 3.1%. 

Regulation: 316(b); 
Range of estimated regional price increases: 0.0-0.4%; 
Estimated national average price increase: 0.1%. 

Regulation: CCR-Solid Waste Option; 
Range of estimated regional price increases: 0.0-1.2%; 
Estimated national average price increase: 0.2%. 

Regulation: CCR-Special Waste Option; 
Range of estimated regional price increases: 0.0-5.6%; 
Estimated national average price increase: 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] Estimates are for regions in the contiguous United States. 

[End of table] 

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.[Footnote 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.[Footnote 68] MISO looked at the price implications of 
all four regulations in its region, projecting a 7 to 7.6 percent 
retail price increase. 

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 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.[Footnote 69] 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 state-
regulated 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. 

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 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. 

Actions May Not Cause Widespread Reliability Concerns but May 
Contribute to Challenges in Some Areas: 

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.[Footnote 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. 
[Footnote 71] 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. 

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. 

Figure 7: Location and Capacity of Planned Coal-Fueled Generating Unit 
Retrofits and Retirements through 2020, as of April 9, 2012: 

[Refer to PDF for image: illustrated U.S. map] 

Depicted on the map: 
 
Capacity of retiring units in MW: 
1,000 or more (3); 
500 to 1,000 (14); 
1 to 500 (50). 

Capacity of retrofitting units in MW: 
1,000 or more (15); 
500 to 1,000 (20); 
1 to 500 (39). 

Sources: GAO analysis of Ventyx data; Map Resources (map).  

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. 

[End of figure] 

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

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

* Retirements. It is not certain what portion of the 2 to 12 percent 
of coal-fueled generating units expected to retire could cause 
reliability challenges that would need to be addressed. Several 
stakeholders said it could be difficult to resolve all potential 
reliability challenges that may arise because of retirements before 
the 3-year MATS compliance deadline established by statute. There have 
been examples in the past of efforts to resolve reliability issues as 
a result of retirements that have taken multiple years to resolve, and 
two of the RTOs we spoke with have identified similar challenges going 
forward. For example, PJM Interconnection (PJM), an RTO system planner 
in the Mid-Atlantic and Midwest, received 116 requests from power 
companies to retire units, as of May 30, 2012--representing 16,184 MW 
of capacity and almost 9 percent of capacity under PJM's authority. 
[Footnote 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.[Footnote 74] 
Similarly, as of May 3, 2012, MISO has identified reliability 
challenges with 8 of the 62 unit retirement notifications it has 
received and completed evaluations on. MISO expects 5 of these to take 
until 2018 to resolve. 

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

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

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

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

Various tools available to industry and regulators could help mitigate 
some, but not all, potential increases in the prices consumers pay for 
electricity. In traditionally regulated markets, in order to determine 
whether to allow power companies to recover the costs of responding to 
the regulations, public utility commissions will hold proceedings to 
review whether power companies' investments in response to the four 
key EPA regulations are prudent. These proceedings could involve 
consideration of whether a power company's compliance strategy--
whether to invest in controls, modify a unit to produce electricity 
using a different fuel source, retire a unit, or build a new unit--is 
defensible. They could also include a review of the actual costs 
involved in installing controls. Once approved by the regulator, 
ratepayers in these markets primarily bear the risk associated with 
actions to comply with the regulations. State public utility 
commissions may also review longer-term resource plans developed by 
power companies to identify when new capacity is needed to accommodate 
unit retirements and, if appropriate, approve power companies' 
proposed approaches for obtaining that capacity--building new units, 
entering into long-term power contracts, or other steps.[Footnote 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.[Footnote 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 well-functioning markets representing the interplay of supply 
and demand. Several stakeholders we spoke with said these processes 
should be effective at keeping power companies from using actions they 
may take in response to the EPA regulations as an opportunity to 
manipulate the electricity markets. 

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

EPA has designed the regulations with some provisions that provide 
flexibility and allow power companies to minimize the costs of 
responding to them, which may reduce consumer electricity price 
increases. For example, by making CSAPR allowances tradable rather 
than requiring all generating units to individually meet a particular 
emissions threshold, EPA may enable power companies to achieve overall 
emissions limits at a lower cost.[Footnote 77] Additionally, EPA 
requested public comment on several regulatory provisions in the 
proposed CCR regulation which, according to EPA officials, could help 
lower industry compliance costs and reduce price increases. 

In addition, some tools could lower demand for electricity, which may 
offset potential price increases. For example, some states have 
provided incentives for consumers to purchase more energy efficient 
household appliances as part of an effort to avoid constructing 
additional generating units. Furthermore, electricity pricing and 
other programs can encourage customers to adjust their usage in 
response to changes in prices or market conditions, which can affect 
reliability. These programs are collectively referred to as "demand-
response" programs, and two types--"market-based pricing" and 
"reliability-driven"--are in use. Market-based pricing programs enable 
customers to adjust their use of electricity in response to changing 
prices. Reliability-driven programs, on the other hand, enable system 
operators to request that customers reduce electricity use when 
needed, such as if hot weather or system malfunctions mean that demand 
will probably exceed supply and cause a blackout. In August 2004, we 
reported that demand-response programs promote greater efficiency in 
supplying electricity by postponing the need to construct new 
generating units and reducing the need to use the generating units 
that are the most costly to operate. We recommended that FERC consider 
the presence or absence of demand response when making key decisions 
about electricity markets, including whether to allow some buyers to 
participate in wholesale markets.[Footnote 78] In response to our 
recommendation, FERC has taken steps to facilitate broader use of 
demand-response programs among RTOs. 

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

Tools available to industry and regulators may also help address many, 
but not all, potential reliability challenges. For example, planning, 
market, and operational tools used by system planners and operators to 
ensure the availability of adequate transmission and generation will 
help address many potential reliability challenges associated with 
these regulations. System planners and operators, whether RTOs or 
individual power companies, manage the electricity system in 
accordance with NERC reliability standards. With respect to 
transmission, system planners compare the long-term demand for 
electricity at various points throughout the system to the location, 
capacity, and operating limits of generation and transmission 
resources. These activities require timely information on, among other 
things, planned retirements and new additions. EPA provided one 
mechanism through which system planners may receive this information 
in a more timely way when it instructed power companies seeking Clean 
Air Act administrative orders--orders to give units up to an 
additional year to come into compliance with MATS--to provide 
compliance plans to system planners. In addition, some RTOs have begun 
requesting that power companies in their regions voluntarily provide 
early information on their plans to respond to the regulations, 
including planned retirements, retrofits, and operational changes. 
With respect to generation, system planner activities vary, with some 
areas of the country planning their future investment in generation 
and others using market-based approaches to encourage the development 
of new generation. System operators take more immediate actions to 
ensure the grid operates in conformance with NERC reliability 
standards, such as directing when to bring additional generation 
online to meet demand or improve system operating conditions. System 
planners and operators must manage changes that power companies make 
to respond to the EPA regulations--retiring generating units, changing 
operating schedules, or scheduling shutdowns to install controls--in a 
way that does not violate NERC's reliability standards. [Footnote 79] 
For example, system planners must maintain adequate contingency 
reserves--such as additional available generation or electricity 
consumers willing to lower their demand for electricity--to address 
any unexpected operational problems that arise, even when some 
electricity generating units retire or are out of service to install 
controls. Broader initiatives in the electric power industry, such as 
activities to promote demand-response and energy efficiency, may also 
help mitigate reliability challenges. 

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

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) reliability-must-run agreements, (5) DOE emergency 
authority, and (6) Clean Air Act section 112 presidential exemption 
authority. However, while these 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.[Footnote 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.[Footnote 81] 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. 

* Clean Air Act administrative orders.[Footnote 82] 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 year.[Footnote 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.[Footnote 84] 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. 

* Clean Air Act consent decrees.[Footnote 85] 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 develop it. In addition, according to EPA 
officials, power companies must be willing to enter into consent 
decrees. However, in the case of a retiring generating unit, it may be 
the system planner, rather than the power company, that wants to keep 
the unit operating. As a result, a power company that wants to retire 
a reliability-critical generating unit may have little incentive to 
enter into a consent decree, particularly if it means paying a penalty 
to do so. 

* Reliability must-run agreements. Reliability must-run agreements--
which provide cost-based payments to the owners of reliability-
critical generating units to cover the cost of operating these units 
past when their owners were planning to retire them--are another 
possible tool for addressing some reliability challenges. These 
agreements have been used in the past to address occasional 
retirements of individual generating units due to changing economic 
conditions, such as when operating a unit became unprofitable. For 
example, a reliability must-run agreement was used to keep Hudson Unit 
1, a 383 MW unit in New Jersey, operational for reliability reasons 
for 7 years after the Public Service Enterprise Group, the power 
company that owns the unit, had requested to retire it. A reliability 
must-run agreement was needed for so long, in part, because of delays 
in the construction of a transmission line that was being developed to 
address potential reliability violations that could occur without the 
new line.[Footnote 86] However, these agreements may not be an option 
for responding to all types of reliability challenges that could arise 
when power companies seek to retire reliability-critical generating 
units in response to the four key regulations. According to 
representatives from some RTOs we spoke to, reliability must-run 
agreements have historically been used to reimburse power companies 
for their operating expenses rather than major capital and other 
expenditures, such as the installation of controls to reduce 
pollution, or financial penalties for violating environmental laws and 
regulations. As such, in situations where a power company plans to 
retire a generating unit, reliability must-run agreements may be 
useful if an administrative order or consent decree can be obtained. 
If not, reliability must-run agreements may be less applicable because 
those units would either have to install controls in order to comply 
or risk financial penalties for noncompliance.[Footnote 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.[Footnote 88] 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. 

[Side bar: DOE's Use of Federal Power Act Section 202(c) for the 
Potomac River Generating Station: 

In 2005, DOE issued a Federal Power Act section 202(c) order to Mirant 
Potomac River, LLC to require it to generate electricity at its
Potomac River Generating Station, a coal-fueled power plant in 
Alexandria, Virginia, that primarily supplied power to Washington,
D.C. In August 2005, after reviewing emissions modeling, Virginia's 
environmental regulator determined that the continued operation of the 
plant at current levels would result in violation of state law and 
regulations and requested that Mirant "immediately undertake such 
action as is necessary to ensure protection of human health and the 
environment." In response, in late August 2005, Mirant reduced 
operations and then shut the plant down. Mirant resumed limited 
operations in late September 2005. In late December 2005, DOE used its 
202(c) authority to order the plant to generate electricity. In June 
2006, EPA issued Mirant a Clean Air Act administrative order, and the
DOE order was amended. According to DOE officials, before issuing a 
202(c) order, DOE needed time to analyze the unique generation and 
transmission details of the Washington, D.C. area; understand the 
plant's operational constraints and environmental requirements; and 
coordinate with Mirant, EPA, the Virginia Department of Environmental 
Quality, and others. 

In 2007, while operating under DOE's order, problems with the plant's 
environmental controls led to a violation of state environmental 
regulations, and state regulators imposed a penalty for failure to (1) 
operate the plant in a manner consistent with minimizing air emissions 
and (2) comply with reporting requirements. According to DOE and 
Virginia officials, the section 202(c) order was designed to allow 
Mirant to operate without violating state environmental law and 
regulations. However, former Mirant officials told us that operation 
at the level specified in the order made a violation unavoidable 
because they could not lower output in order to reduce emissions. 
End of side bar] 

In addition, although DOE may coordinate with EPA and state 
environmental regulators to ensure the section 202(c) order that is 
issued does not result in a violation of environmental requirements, 
some power company representatives expressed concern that operating 
under a section 202(c) order could still result in a potential 
conflict between DOE's order and environmental laws and regulations. 
This could occur if DOE issued a section 202(c) order before agreement 
could be reached with EPA and state environmental regulators on how to 
operate the unit to adequately respond to the emergency and comply 
with applicable environmental laws and regulations.[Footnote 89] 
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 time-consuming which, if 
the process is not started well in advance, may delay steps to address 
reliability. EPA staff commented that the agency will be closely 
tracking cases where extensions and orders are used. 

* 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. 
[Footnote 90] Specifically, the President must make two determinations 
to use this authority: (1) that the technology to implement the 
regulation is not available and (2) that the exemption is in the 
national security interests of the United States. As of May 2012, this 
authority has never been used, and there is uncertainty about whether 
these conditions could be met. For example, as to the first 
determination, EPA established emissions standards for mercury and 
other pollutants that can be met with technology that has been 
available for a significant time. However, according to EPA staff, 
EPA's rulemaking was not intended to and did not consider the 
interpretation of the term 'available' as used in the presidential 
exemption provision. Furthermore, regarding the second determination, 
EPA staff explained that the record supporting EPA's rulemaking 
includes some information that others might consider relevant in 
making any such determination. EPA officials also noted, however, that 
section 112(i)(4) authorizes the President, not EPA, to act. Regarding 
these determinations, according to one stakeholder, it would be 
implausible to claim that technology to comply with MATS is not 
available, and there is not currently evidence of a sufficient threat 
to national security. Another stakeholder, however, has argued that 
the statute is sufficiently broad to allow the exemption authority to 
be used in some situations when a power company does not have the 
physical ability to obtain, purchase, and install technology by the 
deadlines and that the true extent of reliability challenges' threat 
to national security interests cannot be fully known until specific 
reliability studies are completed based on specific compliance plan 
proposals. Several stakeholders we spoke to during this review 
indicated that the presidential exemption authority can be used, 
though two said the statute establishes a high threshold that must be 
met. 

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

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

FERC, DOE, and EPA have begun taking steps to monitor industry's 
progress in responding to the regulations but have not established a 
formal, documented process for joint and routine monitoring, and FERC 
has not taken steps to proactively assess RTO rules in the context of 
the regulations. FERC, DOE, and EPA officials said they have taken 
initial steps to understand the status of industry's plans to respond 
to the regulations, and officials from each agency told us they have 
periodically met with affected stakeholders--for example, power 
companies, state public utility commissions, and all of the RTOs, 
among others--to discuss the regulations' impact and the status of 
industry compliance. For example, staff from all three entities said 
they have had multiple conference calls with RTOs in areas affected by 
the regulations. In addition, FERC hosted a technical conference in 
2011 to discuss policy issues related to the EPA regulations with 
industry stakeholders,[Footnote 91] and FERC and state public utility 
regulators have established a forum to explore reliability challenges 
related to the EPA regulations.[Footnote 92] Furthermore, according to 
EPA staff, the agency had multiple meetings with all of the major 
utility trade associations, as well as a number of large power 
companies with substantial coal-fueled generating capacity, to discuss 
compliance plans and issues that are emerging. However, each agency's 
efforts are varied in scale and scope, and none of the agencies has 
developed a formal, documented process for routinely monitoring 
industry progress, including goals for any monitoring activities, data 
to be collected and analyzed, and how the agencies will use this 
information. Officials from FERC and DOE told us they had not 
formalized their processes for monitoring industry's progress since 
power companies were in the process of finalizing their approach for 
responding to the regulations. 

As discussed, actions power companies take in response to the four 
regulations may present potential reliability challenges, or risks. In 
a December 2005 report on risk management, we reported that monitoring 
is essential in ensuring that a risk management approach is current 
and relevant.[Footnote 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. 
[Footnote 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.[Footnote 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 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.[Footnote 96] 
We reported that agencies can strengthen their commitment to work 
collaboratively by articulating their roles and responsibilities in 
formal documents--such as memorandums of understanding or interagency 
planning documents--to facilitate decision making. These documents can 
clarify which agencies will be responsible for particular activities 
and how they will organize their individual and joint efforts. Without 
more formal coordination mechanisms, any assessment of whether tools 
are sufficient to mitigate potential reliability challenges may not 
fully leverage the perspective of all three agencies, each of which 
has a unique area of expertise and ability to perform different 
analysis. Each of the three agencies may have knowledge of whether 
particular tools are useful for addressing actual reliability 
challenges, and DOE and FERC may be able to provide insight into the 
magnitude and urgency of such challenges. 

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

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

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

Region: ERCOT[A]; 
Concern about RTO market rule: 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; 
Potential change and status: Modify outage rules so ERCOT can deny 
outages that pose reliability challenges. (Concern identified). 

Region: MISO; 
Concern about RTO market rule: 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; 
Potential change and status: 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). 

Region: MISO; 
Concern about RTO market rule: 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; 
Potential change and status: Modify market rules to encourage the 
development of additional "quick-start" capacity. (Under discussion). 

Region: MISO; 
Concern about RTO market rule: 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; 
Potential change and status: 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). 

Region: ISO New England; 
Concern about RTO market rule: 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; 
Potential change and status: 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). 

Region: PJM; 
Concern about RTO market rule: 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; 
Potential change and status: Revise PJM's transmission planning 
process to allow it to better manage uncertainty about "at-risk" 
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. 

[End of table] 

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

Conclusions: 

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

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

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

Recommendations for Executive Action: 

We are making the following two recommendations: 

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

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

Agency Comments and Our Evaluation: 

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

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

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

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

As agreed with your office, unless you publicly announce the contents 
of this report earlier, we plan no further distribution until 30 days 
from the report date. At that time, we will send copies to the 
appropriate congressional committees, the Secretary of Energy, 
Chairman of FERC, Administrator of the EPA, and other interested 
parties. In addition, the report will be available at no charge on the 
GAO website at [hyperlink, http://www.gao.gov]. 

If you or your staff members have any questions about this report, 
please contact Frank Rusco at (202) 512-3841 or ruscof@gao.gov or 
David Trimble at (202) 512-3841 or trimbled@gao.gov. Contact points 
for our Offices of Congressional Relations and Public Affairs may be 
found on the last page of this report. GAO staff who made key 
contributions to this report are listed in appendix VIII. 

Sincerely yours, 

Signed by: 

Frank Rusco: 
Director, Natural Resources and Environment: 

Signed by: 

David C. Trimble: 
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Scope and Methodology: 

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

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

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

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

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

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

[End of section] 

Appendix II: List of Stakeholders: 

Federal Agencies:
1. Department of Energy:
2. Environmental Protection Agency:
3. Federal Energy Regulatory Commission: 

State Electricity and Environmental Regulators:
4. Georgia:
5. Kentucky:
6. Missouri:
7. Ohio:
8. Pennsylvania:
9. Texas: 

Regional Transmission Organizations:
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: 

Power Companies:
16. American Electric Power:
17. Big Rivers Electric Corporation:
18. Calpine:
19. City Utilities of Springfield:
20. Exelon Corporation:
21. First Energy:
22. GenOn Energy:
23. Southern Company:
24. Tennessee Valley Authority: 

Other:
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: 

[End of section] 

Appendix III: List of Studies: 

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

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

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

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

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

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

IHS Global Insight. US Energy Outlook. September 2011. 

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

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

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

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

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

[End of section] 

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

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

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

[Refer to PDF for image: illustrated U.S. map] 

Western Electricity Coordinating Council: 
Capacity: 32,281; 
Share: 17%. 

Midwest Reliability Organization: 
Capacity: 25,256; 
Share: 46%. 

SERC Reliability Corporation: 
Capacity: 98,540; 
Share: 37%. 

Southwest Power Pool Regional Entity: 
Capacity: 21,299; 
Share: 36%. 

Northeast Power Coordinating Council: 
Capacity: 4,838; 
Share: 7%. 

SERC Reliability Corporation and Southwest Power Pool Regional 
Entity[A]: 

Texas Reliability Entity: 
Capacity: 19,176; 
Share: 22%. 

Florida Reliability Coordinating Council: 
Capacity: 9,390; 
Share: 17%. 

ReliabilityFirst Corporation: 
Capacity: 102,750; 
Share: 47%. 

Sources: GAO analysis of Ventyx data, North American Electric 
Reliability Corporation, and Map Resources (map). 

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. 

[End of figure] 

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. 

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

Primary pollutant targeted: Particulate matter[A]; 
Equipment name: Electrostatic precipitator; 
How it works: An induced electrical charge removes particles from flue 
gas; 
Removal efficiency: 99.5%. 

Equipment name: Primary pollutant targetedSO2 and other acid gases[B]: 
Fabric filter (commonly referred to as a "baghouse"); 
How it works: Primary pollutant targetedSO2 and other acid gases[B]: 
Flue gas passes through tightly woven fabric filter "bags" that filter 
out the particulates; 
Removal efficiency: Primary pollutant targetedSO2 and other acid 
gases[B]: 99.9%. 

Primary pollutant targeted: SO2 and other acid gases[B]; 
Equipment name: Flue gas desulfurization unit (commonly referred to as 
a "scrubber"); 
How it works: 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; 
Removal efficiency: Wet scrubbers - 99% removal of SO2; Dry 
scrubbers - 95% removal of SO2. 

Primary pollutant targeted: SO2 and other acid gases[B]; 
Equipment name: Dry sorbent injection unit; 
How it works: An alkaline powdered material is injected into the flue 
gas (postcombustion) to react with the SO2 and other acid gases. The 
resulting product is then collected through a particulate matter 
control device; 
Removal efficiency: 50% with an electrostatic precipitator, 75% with a 
fabric filter. 

Primary pollutant targeted: Nitrogen oxides (NOx); 
Equipment name: Combustion control technologies, such as low-NOx 
burners[C]; 
How it works: Coal combustion conditions are adjusted so less NOx is 
formed; 
Removal efficiency: 45% reduction in the formation of NOx. 

Equipment name: Primary pollutant targeted Mercury[D]: Post-combustion 
controls, such as selective catalytic reduction (SCR) and selective 
non-catalytic reduction (SNCR) units; 
How it works: Primary pollutant targeted Mercury[D]: 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 as well but do not use a catalyst; 
Removal efficiency: Primary pollutant targeted Mercury[D]: SCRs - 95% 
removal of NOx; SNCRs -75% removal of NOx. 

Primary pollutant targeted: Mercury[D]; 
Equipment name: Activated carbon injection units; 
How it works: Activated carbon is injected into flue gas, binds with 
mercury, and is collected in a particulate matter control device; 
Removal efficiency: 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] 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. 

[End of table] 

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. 

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

[Refer to PDF for image: 4 vertical bar graphs] 

Particulate matter: 

Year: 2000; 
Fabric filter: 0.785; 
Electrostatic precipitator: 0.766. 

Year: 2001; 
Fabric filter: 1.772; 
Electrostatic precipitator: 1.402. 

Year: 2002; 
Fabric filter: 0.684; 
Electrostatic precipitator: 0.328. 

Year: 2003; 
Fabric filter: 1.094; 
Electrostatic precipitator: 0.3. 

Year: 2004; 
Fabric filter: 0.673; 
Electrostatic precipitator: 0. 

Year: 2005; 
Fabric filter: 0.431; 
Electrostatic precipitator: 0. 

Year: 2006; 
Fabric filter: 1.212; 
Electrostatic precipitator: 0. 

Year: 2007; 
Fabric filter: 4.096; 
Electrostatic precipitator: 0. 

Year: 2008; 
Fabric filter: 4.195; 
Electrostatic precipitator: 0.51. 

Year: 2009; 
Fabric filter: 5.818; 
Electrostatic precipitator: 1.137. 

Year: 2010; 
Fabric filter: 4.033; 
Electrostatic precipitator: 0.586. 

Year: 2011; 
Fabric filter: 1.34; 
Electrostatic precipitator: 0. 

Sulfur dioxide: 

Year: 2000; 
Scrubber[A]: 0; 
Dry sorbent injection unit: 0. 

Year: 2001; 
Scrubber[A]: 2.699; 
Dry sorbent injection unit: 0. 

Year: 2002; 
Scrubber[A]: 2.476; 
Dry sorbent injection unit: 0. 

Year: 2003; 
Scrubber[A]: 0; 
Dry sorbent injection unit: 0. 

Year: 2004; 
Scrubber[A]: 0.335; 
Dry sorbent injection unit: 0. 

Year: 2005; 
Scrubber[A]: 0.54; 
Dry sorbent injection unit: 0. 

Year: 2006; 
Scrubber[A]: 4.444; 
Dry sorbent injection unit: 0. 

Year: 2007; 
Scrubber[A]: 14.771; 
Dry sorbent injection unit: 0. 

Year: 2008; 
Scrubber[A]: 18.724; 
Dry sorbent injection unit: 0. 

Year: 2009; 
Scrubber[A]: 23.595; 
Dry sorbent injection unit: 0.749. 

Year: 2010; 
Scrubber[A]: 19.219; 
Dry sorbent injection unit: 0.15. 

Year: 2011; 
Scrubber[A]: 7.288; 
Dry sorbent injection unit: 0. 

Nitrogen oxides: 

Year: 2000; 
Selective catalytic reduction unit: 3.848; 
Selective non-catalytic reduction unit: 0.18. 

Year: 2001; 
Selective catalytic reduction unit: 9.731; 
Selective non-catalytic reduction unit: 0.46. 

Year: 2002; 
Selective catalytic reduction unit: 12.652; 
Selective non-catalytic reduction unit: 0.164. 

Year: 2003; 
Selective catalytic reduction unit: 36.805; 
Selective non-catalytic reduction unit: 2.105. 

Year: 2004; 
Selective catalytic reduction unit: 16.038; 
Selective non-catalytic reduction unit: 3.026. 

Year: 2005; 
Selective catalytic reduction unit: 7.476; 
Selective non-catalytic reduction unit: 1.707. 

Year: 2006; 
Selective catalytic reduction unit: 2.62; 
Selective non-catalytic reduction unit: 3.811. 

Year: 2007; 
Selective catalytic reduction unit: 5.974; 
Selective non-catalytic reduction unit: 1.589. 

Year: 2008; 
Selective catalytic reduction unit: 3.213; 
Selective non-catalytic reduction unit: 3.75. 

Year: 2009; 
Selective catalytic reduction unit: 7.525; 
Selective non-catalytic reduction unit: 5.506. 

Year: 2010; 
Selective catalytic reduction unit: 4.578; 
Selective non-catalytic reduction unit: 0.69. 

Year: 2011; 
Selective catalytic reduction unit: 1.641; 
Selective non-catalytic reduction unit: 6.046. 

Mercury: 

Year: 2000; 
Activated carbon injection unit: 0. 

Year: 2001; 
Activated carbon injection unit: 0. 

Year: 2002; 
Activated carbon injection unit: 0. 

Year: 2003; 
Activated carbon injection unit: 0. 

Year: 2004; 
Activated carbon injection unit: 0. 

Year: 2005; 
Activated carbon injection unit: 0. 

Year: 2006; 
Activated carbon injection unit: 0.113. 

Year: 2007; 
Activated carbon injection unit: 1.398. 

Year: 2008; 
Activated carbon injection unit: 4.458. 

Year: 2009; 
Activated carbon injection unit: 28.603. 

Year: 2010; 
Activated carbon injection unit: 5.535. 

Year: 2011; 
Activated carbon injection unit: 0.575. 

Source: GAO analysis of Ventyx data. 

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. 

[End of figure] 

Figure 10 and Figure 11: Percentage of Coal-Fueled Generating Capacity 
with Air Pollution Controls Installed by Region, as of April 9, 2012: 

[Refer to PDF for image: illustrated U.S. map with 32 associated pie-
charts] 
    
1. Western Electricity Coordinating Council; 
2. Midwest Reliability Organization; 
3. ReliabilityFirst Corporation; 
4. Northeast Power Coordinating Council; 
5. SERC Reliability Corporation; 
6. Florida Reliability Coordinating Council; 
7. Texas Reliability Entity; 
8. Southwest Power Pool Regional Entity. 

Western Electricity Coordinating Council: 

Particulate matter: 
None: 1%; 
ESP: 32%; 
Fabric filter: 57%; 
Other: 10%. 

SO2: 
None: 9%; 
Scrubber: 89%; 
DSI: 0%; 
Other: 2%. 

NOx: 
None: 4%; 
SCR: 8%; 
SNCR: 15%; 
Other: 73%. 

Mercury[A]: 
None: 80%; 
ACI: 20%. 

Midwest Reliability Organization: 

Particulate matter: 
None: 2%; 
ESP: 57%; 
Fabric filter: 41%; 
Other: 0%. 

SO2: 
None: 51%; 
Scrubber: 47%; 
DSI: 0%; 
Other: 2%. 

NOx: 
None: 11%; 
SCR: 13%; 
SNCR: 16%; 
Other: 60%. 

Mercury[A]: 
None: 78%; 
ACI: 22%. 

ReliabilityFirst Corporation: 

Particulate matter: 
None: 1%; 
ESP: 87%; 
Fabric filter: 10%; 
Other: 2%. 

SO2: 
None: 39%; 
Scrubber: 59%; 
DSI: 0%; 
Other: 2%. 

NOx: 
None: 3%; 
SCR: 52%; 
SNCR: 16%; 
Other: 29%. 

Mercury[A]: 
None: 87%; 
ACI: 13%. 

Northeast Power Coordinating Council: 

Particulate matter: 
None: 2%; 
ESP: 57%; 
Fabric filter: 41%; 
Other: 0%. 

SO2: 
None: 39%; 
Scrubber: 40%; 
DSI: 19%; 
Other: 3%. 

NOx: 
None: 2%; 
SCR: 45%; 
SNCR: 27%; 
Other: 26%. 

Mercury[A]: 
None: 48%; 
ACI: 52%. 

SERC Reliability Corporation: 

Particulate matter: 
None: 0%; 
ESP: 83%; 
Fabric filter: 15%; 
Other: 2%. 

SO2: 
None: 42%; 
Scrubber: 56%; 
DSI: 0%; 
Other: 2%. 

NOx: 
None: 3%; 
SCR: 50%; 
SNCR: 12%; 
Other: 34%. 

Mercury[A]: 
None: 90%; 
ACI: 10%. 

Florida Reliability Coordinating Council: 

Particulate matter: 
None: 3%; 
ESP: 81%; 
Fabric filter: 16%; 
Other: 0%. 

SO2: 
None: 12%; 
Scrubber: 85%; 
DSI: 0%; 
Other: 3%. 

NOx: 
None: 1%; 
SCR: 70%; 
SNCR: 9%; 
Other: 21%. 

Mercury[A]: 
None: 95%; 
ACI: 5%. 

Texas Reliability Entity: 

Particulate matter: 
None: 2%; 
ESP: 45%; 
Fabric filter: 53%; 
Other: 0%. 

SO2: 
None: 31%; 
Scrubber: 64%; 
DSI: 0%; 
Other: 5%. 

NOx: 
None: 3%; 
SCR: 29%; 
SNCR: 19%; 
Other: 49%. 

Mercury[A]: 
None: 57%; 
ACI: 43%. 

Southwest Power Pool Regional Entity: 

Particulate matter: 
None: 2%; 
ESP: 67%; 
Fabric filter: 25%; 
Other: 6%. 

SO2: 
None: 54%; 
Scrubber: 40%; 
DSI: 0%; 
Other: 6%. 

NOx: 
None: 5%; 
SCR: 17%; 
SNCR: 16%; 
Other: 62%. 

Mercury[A]: 
None: 97%; 
ACI: 3%. 

Legend: ESP = electrostatic precipitator; 
DSI = dry sorbent injection unit; 
SCR = selective catalytic reduction unit; 
SNCR = selective non-catalytic reduction unit; 
ACI = activated carbon injection unit.  

Sources: GAO analysis of Ventyx data, North American Electric 
Reliability Corporation, and Map Resources (map). 

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. 

[End of figure] 

[End of section] 

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. 

Federal Energy Regulatory Commission: 
Office of The Chairman: 
Washington, DC 20426: 

July 3, 2012: 

Mr. Frank Rusco: 
Director Natural Resources and Environment: 
United States Government Accountability Office: 
441 G Street, NW: 
Washington, DC 20548: 

Dear Mr. Rusco: 

Thank you for your June 6, 2012 electronic transmission of the draft 
report, EPA Regulations and Electricity: Better Monitoring by Agencies 
Could Strengthen Efforts to Address Potential Challenges. I appreciate 
the opportunity to comment on this draft report. 

In general, the draft report provides useful discussion of this issue.
However, the draft report's ultimate conclusions and recommendations are
incorrect in two ways. As more fully described below, it does not take 
into account a number of actions the Federal Energy Regulatory 
Commission (FERC or Commission) has taken as the electricity industry 
works to comply with new Environmental Protection Agency (EPA) 
regulations. We also publicly committed to working closely with 
industry, the states and other agencies to address any issues that 
arise. The Commission is already implementing a variety of policies, 
including those you recommend, to ensure that our electricity system 
remains reliable. Here are a few of the steps we have taken that were 
not discussed in the draft report. I respond to the report's specific 
recommendations in more detail below. [See comment 1] 

* The Commission has already held one conference specifically to 
examine the processes that Planning Authorities and other entities use 
to identify and address reliability concerns that may arise in the 
course of compliance with EPA regulations. To the extent additional 
analysis or evidence would aid the Commission's efforts to monitor and 
act on these issues, we will hold additional conferences or workshops. 

* The Commission recently issued a Policy Statement detailing how our 
coordination with EPA on compliance to the new mercury and air toxic 
standards rule will work. 

* The Commission participates in a regular public forum with state
commissioners, the National Association of Regulatory Utility
Commissioners (NARUC)/FERC Forum on Reliability and the Environment. 

* The Commission and its staff review plans, reports and other 
information generated by the Planning Authorities, industry and other 
stakeholders regarding the impact of compliance with EPA regulations. 

* Commission staff routinely communicates with the EPA and the 
Department of Energy (DOE) on this topic. 

* The Commission staff, DOE, and EPA are working to establish a more 
formalized approach to continued coordination and discussion of issues 
arising from the industry's response to EPA regulations. 
[See comment 1] 

Should the final report not take into account these actions, it will be
incorrect in failing to recognize both that the Commission had 
undertaken before issuance of the draft report many of the actions the 
draft report proposes and that the Commission has taken additional 
actions after issuance of the draft report in furtherance of its 
recommendations. 

As noted in the report, the Commission has an important role in 
overseeing the reliability of the bulk-power system. I take that role 
seriously, and have taken several steps to discuss issues concerning 
the EPA regulations and reliability with industry and EPA and DOE. As 
a part of this role, on May 17, 2012, the Commission issued a policy 
statement outlining how it will advise the EPA on requests for 
additional time for electric generators to comply with the new EPA 
mercury and air toxics standards rule. The Commission issued this 
policy statement after considering a staff white paper on the subject 
and numerous comments received on the staff white paper. Although my 
staff shared these documents with your office, neither the January 
white paper nor the Policy Statement was discussed in the draft 
report. A copy of the Policy Statement is enclosed again. Below, I 
address the recommendations in the draft report in several important 
respects. [See comment 2] 

The draft report first recommends that FERC, EPA and DOE develop and 
document a formal, joint process to monitor industry's progress in 
responding to the EPA regulations. I agree with the goal of open 
communication and have had Commission staff engage extensively with 
EPA and DOE on these issues. Commission staff has had numerous 
meetings with EPA and DOE to discuss the issues involved and continues 
to meet with EPA and DOE. With respect to creating a formal process, 
as an independent agency, the Commission cannot dictate the sharing of 
information with and by other parts of the government. The Commission 
staff, DOE, and EPA are working to establish a more formalized 
approach to continued coordination and discussion of issues arising 
from the industry's response to EPA regulations to the extent our 
authority allows. [See comment 3] 

Further, the draft report is incorrect that the Commission has had 
only informal coordination with power companies and others about their 
actions in response to the regulations. The Commission has held 
numerous meetings with representatives from EPA, DOE and the industry 
on these issues, including two public meetings. The Commission held a 
reliability conference on November 30, 2011 to discuss the processes 
that Planning Authorities and other entities use to identify and 
address reliability concerns that may arise in the course of 
compliance with EPA regulations. Representatives from EPA and DOE 
participated in this conference and GAO representatives were invited 
to and attended this conference. At this conference, the Commission 
addressed issues such as how reliability aspects of EPA's proposed and 
final regulations should be addressed, what local or regional 
processes are used to plan for emerging issues such as the EPA 
regulations, and how the industry is incorporating the EPA regulations 
into this process. The Commission received numerous written comments 
following this reliability conference. [See comment 4] 

The Commission has also joined with NARUC to convene an ongoing Forum 
to explore reliability issues stemming from new and pending 
environmental rules for the power sector. FERC and NARUC initiated the 
Forum as part of an effort to determine how prepared the electric 
utility industry will be to meet upcoming rules and requirements on 
emissions reductions. Future meetings will coincide with NARUC's three 
yearly meetings. The first meeting of the FERCNARUC Forum on 
Reliability and the Environment took place on February 7, 2012 and the 
next meeting will be held in July. 

With respect to monitoring the industry's progress, the Policy 
Statement noted that the existing processes used by the Planning 
Authorities to conduct reliability assessments, which are based on the 
NERC planning standards and performed under NERC's oversight, appear 
to be sufficient. The Commission will continue to monitor Planning 
Authorities' efforts on these matters. Since issuance of the Policy 
Statement, Commission staff, EPA, and DOE have participated in several 
conference calls with RTOs to discuss their efforts to plan the system 
for future need, including implementation of the EPA rules. Future 
meetings are planned, and staff has scheduled a meeting with the 
Planning Authorities in the Southeast to discuss their planning 
activities. As provided in the Policy Statement, the Commission has 
committed that Commission staff is available to Planning Authorities 
and participants in these processes for consultation on these matters. 
[Footnote 1] [See comment 54] 

Further, the Policy Statement affirms that the Commission is engaged 
in other efforts to monitor the impact of EPA regulations generally on 
bulk-power system reliability. For example, the Commission and its 
staff will continue to review plans, reports and other information 
generated by the Planning Authorities, industry and other stakeholders 
regarding the impact of compliance with EPA regulations. The 
Commission stated that to the extent additional analysis or evidence 
would aid the Commission's efforts to monitor these issues, it will 
consider holding additional reliability conferences or workshops. 
[Footnote 2] [See comment 5] 

Finally, the Commission's Policy Statement makes clear that the lines 
of communication should remain open. It specifically provided that 
Commission staff will also be available to communicate with the EPA on 
any reliability-related issues to aid the EPA in its consideration of 
these issues.[Footnote 3] The Policy Statement also identified types 
of information industry applicants could provide to assist the 
Commission in its timely review of requests for Administrative Orders 
from the
EPA. 

The second recommendation in the draft report is for me as the 
Chairman of the Commission to assess the adequacy of existing RTO 
market rules and similar rules of non-RTO planning authorities. I 
believe this recommendation is founded on incorrect information 
because I have already met it. The Commission continually assesses the 
rules of the entities over which it has jurisdiction, and it has 
specifically explored whether changes are needed to respond to the EPA 
regulations. [See comment 6] 

With respect to analyzing tariffs and market rules in light of the EPA 
regulations, the Commission's November 30, 2011, reliability 
conference addressed this exact issue. The Commission explicitly asked 
participants what market structures and tariff rules are used to 
address local and regional reliability issues that may arise from 
generation retirements potentially triggered by EPA regulations and 
whether any changes to market and tariff rules are needed. The
Commission also asked participants to address if they have the right 
tools to identify any problems that may arise and what, if any, other 
process changes could help address reliability-related requests for 
exemptions from the EPA regulations. During the reliability 
conference, Commissioners questioned panelists on whether new tools 
are needed.[Footnote 4] The overwhelming response from panelists and 
commenters was that no significant changes are needed to the market 
rules at this time. Thus I have already fulfilled the draft report's 
second recommendation. 

Further, the Commission continually assesses the tariffs pursuant to 
which public utilities operate. For example, in its recent rulemaking 
evaluating the adequacy of transmission planning processes, the 
Commission evaluated its existing regulations and proactively required 
public utility transmission providers to amend their planning 
processes to address compliance with public policy requirements. 
Public policy requirements in this context can include requirements
under EPA regulations.[Footnote 5] By October 2012, public utility 
transmission providers must submit to the Commission compliance 
filings describing the process by which they will evaluate potential 
solutions to transmission needs driven by public policy requirements. 
The Commission specifically acknowledged that evaluation of 
transmission needs driven by public policy requirements could require 
the gathering of additional information from interconnected generators 
regarding retirements. The Commission invited public utility 
transmission providers to include in their compliance filings 
amendments to existing tariff provisions necessary to gather such 
information.[Footnote 6] [See comment 6] 

The Commission has also met the draft report's recommendation that the
Commission consider the presence or absence of demand response when 
making key decisions about electricity markets and that the Commission 
should be able to quickly and effectively review whether steps should 
be taken to require RTOs or other market participants to secure 
additional demand response resources. When I first came to the 
Commission, I stated my belief that demand resources could reduce the 
costs of electric service and provide several other benefits to 
consumers. My colleagues and I have worked to provide the opportunity 
for demand resources to participate in wholesale markets, assist in 
efficient transmission service and maintain the reliability of the 
electric system. The Commission has issued several regulations to 
eliminate barriers to demand response participation in organized 
markets. For example, Order No. 719 made several reforms to eliminate 
barriers to demand response participation in organized energy markets 
and to ensure that demand response is treated comparably to other 
resources.[Footnote 7] Order No. 745 modified the Commission's 
regulations concerning compensation for demand response.[Footnote 8] 
That rule provides more resource options for efficient and reliable 
system operation; it encourages new entry and competition in energy 
markets, and it spurs the deployment of new technologies. [See comment 
7] 

The draft report next asserts that the Commission does not have plans 
to evaluate whether changes proposed by one RTO may be useful at 
others. I disagree with this recommendation. Each RTO market is 
structured differently and, where appropriate, the Commission has 
allowed regional approaches that make sense in the context of each 
RTO's market. What works in one RTO may not in another. Dictating a 
federal one-size-fits-all approach on matters related to EPA 
regulations could be problematic, particularly when the Commission 
already has explored whether changes are needed. [See comment 8] 

Further, the draft report asserts that, if there are a larger number 
of local reliability challenges, the Commission may be less able to 
effectively and quickly manage reviewing several types of issues. 
However, the Commission routinely processes the filings it receives in 
a timely, effective manner. For example, applications for cost 
recovery for transmission investments and reliability-must run 
agreements will generally be made under section 205 of the Federal 
Power Act (FPA). Section 205 cases are proposals by public utility 
service providers to adopt or revise rates, terms or conditions for 
Commission jurisdictional power or transmission services. The 
statutory deadline for issuance of section 205 orders typically is 60 
days from the date of filing, and the Commission has a long history of 
meeting this deadline. [See comment 9] 

The draft report is also concerned about requests for reliability-
critical status from plants seeking an additional year for compliance 
under the EPA's MATS Rule. As stated above, the draft report does not 
acknowledge that Commission staff issued a white paper in January 
concerning this issue or that the Commission recently issued a Policy 
Statement outlining the procedure for reviewing these filings. As 
stated in the Policy Statement, these procedures were specifically 
crafted to ensure that the Commission can provide timely comments to 
the EPA. [See comment 10] 

Thank you again for the opportunity to comment on your draft report. 
While, the draft report provides useful discussion of this issue, the 
ultimate conclusions and recommendations are incorrect because they 
ignore actions the Commission has taken and continues to take 
regarding these issues. As the Commission stated in its recent Policy 
Statement, the Commission intends to continue addressing these issues 
with state commissions in a regular public forum, the NARUC/FERC Forum 
on Reliability and the Environment. The Commission and its staff will 
also continue to review plans, reports and other information generated 
by the Planning Authorities, industry and other stakeholders regarding  
the impact of compliance with EPA regulations, and to communicate with 
the EPA and DOE on this topic. To the extent additional analysis or 
evidence would aid the Commission's efforts to monitor these issues, 
we will consider holding additional reliability conferences or 
workshops. The Commission also seeks to engage industry and other 
federal agencies on issues relating to electric reliability. FERC's 
door is always open and we have consistent interaction with industry 
on any number of reliability and market concerns. Finally, in 
recognition of the recommendation in the draft report, Commission 
staff, DOE, and EPA are working to establish a more formalized 
approach to continued coordination and discussion of issues arising 
from the industry's response to EPA regulations. The final report 
should acknowledge these actions and not repeat the draft report's  
incorrect assertions. I am happy to discuss these issues with you at 
any time. 

Sincerely, 

Signed by: 

John Wellinghoff:  
Chairman: 

Footnotes: 

1. The Commission's Role Regarding the Environmental Protection 
Agency's Mercury and Air Toxics Standards, 139 FERC ¶ 61,131 at n. 17 
(2012) (Policy Statement). 

2. Id. at P 23. 

3. Id. at n.23. 

4. See, e.g., Reliability Technical Conference, Nov. 29, 2011 Tr. 263, 
In 19—264, In. 4. 

5. Transmission Planning and Cost Allocation by Transmission Owning 
and Operating Public Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 
31,323 at P 215 (2011). 

6. Id. atP 211,n.190. 

7. Order No. 719, FERC Stats. & Regs. ¶ 31,281. 

8. Demand Response Compensation in Organized Wholesale Energy Markets, 
Order No. 745, 76 Fed. Reg. 16,658 (Mar. 24, 2011), FERC Stats. & 
Regs. ¶ 31,322 (2011). 

The following are GAO's comments on the Federal Energy Regulatory 
Commission's letter dated July 3, 2012. 

GAO Comments: 

1. We recognize that FERC has taken a number of positive actions 
related to the EPA regulations, and we have described these in our 
draft and final report. We have made some clarifying changes and, in 
one case, added language about an example we had not previously 
described in the report in response to these comments. 

2. The scope of FERC's policy statement is limited to describing how 
FERC intends to provide advice to EPA on requests for administrative 
orders to bring a source into compliance with MATS within 1 year. It 
provides a useful description of FERC's role with respect to this tool 
for addressing potential reliability challenges, but it does not 
establish a formal, documented process for FERC's overall monitoring 
effort or for its coordination with EPA and DOE. We added a 
description of FERC's policy statement where we describe FERC's role 
with respect to MATS in response to this comment. 

3. We agree that multiagency coordination can be difficult. When we 
met with FERC, EPA, and DOE during the course of our audit work, the 
agencies had not documented a formal process for monitoring. In 
response to our draft report, these agencies said they are working to 
establish such an approach. We commend these agencies for taking this 
step and believe it is important that they complete this effort. We 
acknowledge there may be limits on the extent to which agencies can 
collaborate and clarified our recommendation accordingly. 

4. We acknowledge that FERC has gathered views on the potential 
implications of these regulations from various affected parties, 
including at formal events such as FERC's 2011 technical conference 
and the February 2012 forum with state regulators. Our observation 
from attending these events is that they fostered a useful exchange of 
ideas and perspectives about the potential implications of the EPA 
regulations. However, the actual implications will only be known once 
electricity generating unit owners finalize their plans for responding 
to the regulations and begin to take steps to retrofit or retire units-
-which will occur over the next several years. We believe that 
additional monitoring will be important and that the actions noted by 
FERC do not represent the type of formal, documented process that will 
be needed for successfully monitoring industry's progress in 
responding to the regulations or for FERC's coordination with DOE and 
EPA in this effort. We believe there are risks to relying on informal 
mechanisms and that a formal, documented process could help strengthen 
FERC's future efforts at identifying potential problems. As such, we 
made no changes in response to this comment. 

5. We believe that the NERC-overseen reliability assessments, plans 
and reports from other stakeholders, as well as conferences and 
workshops, can all be useful in an overall monitoring effort. We 
encourage FERC to work with NERC and other stakeholders in monitoring 
industry progress to the extent that FERC determines such activities 
to be useful. We maintain that FERC should formalize this process and 
document it if the agency intends for this monitoring to continue in 
the future. We made no change in response to this comment. 

6. We acknowledge that FERC periodically performs various assessments 
of the adequacy of existing RTO market rules and similar rules of non- 
RTO system planners and, where FERC believes it is appropriate, 
encourages changes. However, based on our conversations with FERC 
officials, FERC had not proactively assessed the adequacy of system 
planner rules in light of the EPA regulations to determine whether 
changes are needed or if improvements at one system planner could be 
useful at another. We also acknowledge that there was a useful 
exchange of ideas and perspectives about the need for potential 
changes in market rules at FERC's technical conference, but we do not 
believe that the gathering of these views is a substitute for an 
assessment by FERC of the adequacy of these rules. In addition, FERC's 
recent rulemakings are positive steps, but they do not reflect an 
assessment of whether rules need to be modified in light of the EPA 
regulations to ensure timely, cost-effective mitigation of potential 
reliability challenges that may be associated with the regulations. We 
made no change in response to this comment. 

7. Neither the draft report, nor the final report recommends that FERC 
consider the presence or absence of demand response when making key 
decisions about electricity markets. FERC's comment refers to text in 
our draft report that referred to a recommendation in our 2004 report 
on demand response. We made this reference to highlight that demand 
response is a tool that could lower demand for electricity to mitigate 
the price or reliability implications of the EPA regulations and to 
note that FERC has taken a number of steps to facilitate broader use 
of demand response among RTOs. As noted in the conclusion of this 
report, we believe that demand response could provide an important 
mechanism that could mitigate potential reliability challenges, should 
they arise. As such, it may be useful for FERC to consider whether 
there are certain approaches related to demand response at one or more 
RTOs that could be encouraged elsewhere or whether the presence or 
adequacy of demand response in a market should be used when making 
decisions regarding market rules. We made no change in response to 
this comment. 

8. We do not suggest that a one-size-fits-all approach would be best, 
and believe efforts to develop the RTOs and other institutions 
requires leveraging prior entities' experiences. FERC may have the 
opportunity to take a more proactive role in narrowing these 
differences to the benefit of market participants overseen by FERC and 
the consumers who are ultimately served by these markets. We made no 
change in response to this comment. 

9. We do not assert that FERC will be unable to meet its statutory 
deadlines for review of transmission investments and reliability must-
run agreements. Rather, we suggest that information from a formal, 
documented monitoring effort could help alert agencies in advance if a 
larger or smaller than expected number of reliability challenges 
arises, which could be useful for managing its staffing and 
operations. We made no change in response to this comment. 

10. We agree that FERC's policy statement provides clarity about the 
process FERC intends to take to provide timely comments to EPA on 
requests for administrative orders to bring a source into compliance 
with MATS within 1 year. However, we continue to believe that a 
documented, formal monitoring process--by giving FERC insight into the 
extent of potential reliability challenges--could aid FERC in managing 
its process for providing input to EPA. We made no change in response 
to this comment. 

[End of section] 

Appendix VI: Comments from the Department of Energy: 

Department of Energy: 
Washington, DC 20585: 

July 3, 2012: 

Mr. Prank Rusco: 
Director: 
Natural Resources and Environment: 
U.S. Government Accountability Office: 
Washington, DC 20548: 

Dear Director Rusco: 

The Department of Energy (DOE) appreciates the opportunity to respond 
to the Government Accountability Office's (GAO) Draft Audit Report 
"EPA Regulations and Electricity: Better Monitoring by Agencies Could 
Strengthen Efforts to Address Potential Challenges." 

DOE's response to the Report's draft recommendation that involves DOE 
is as follows: 

Recommendation 1: "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 
to monitor industry's progress in responding to the EPA regulations 
until at least 2017. Each agency, to the extent practical, should 
leverage resources and share the results of its efforts with the other 
agencies. The agencies should consider providing Congress with the 
results of their monitoring efforts, including whether additional 
statutory authority is needed to address any potential adverse 
implications." 

Response: DOE concurs with the recommendation to "develop and document a
formal, joint process to monitor industry's progress in responding to 
the EPA regulations..." among FERC, DOE, and EPA. An effort to 
document through a formal process the current (as the draft report 
notes) coordinated monitoring by our three agencies is currently 
underway. DOE agrees that coordination between it, the Environmental 
Protection Agency (EPA) and the Federal Energy Regulatory Commission 
(FERC) is an important part of successfully addressing any potential 
reliability challenges within the electricity sector as a result of 
EPA's recent suite of regulations. 

Additionally, the Department will continue to offer technical 
assistance to states and other stakeholders. Such technical assistance 
is expected to help inform, rather than direct, decisions regarding 
implications from EPA's regulations. This technical assistance may 
relate to the retire vs. retrofit decision for generation units over 
which a state has oversight, including options for replacement energy 
in case of a retirement. For example, two weeks ago DOE, at the 
invitation of the Ohio Public Utilities Commission, provided input 
into a commission workshop on combined heat and power, and hosted a
Midwest combined heat and power dialogue meeting. Earlier this year, 
DOE provided assistance to another state on technology options on the 
retire vs. retrofit issue, as well helping a state's utility 
commission think through the implications for the electricity planning 
process it oversees in light of the EPA regulations. 

Finally, with respect to DOE's emergency authority under section 
202(c) of the Federal Power Act, DOE views this authority as a tool of 
last resort to address reliability emergencies when all other options 
have been exhausted. DOE has issued an emergency order in only one 
case where environmental regulations played a direct role. In this 
instance, DOE worked closely with both EPA and the state environmental 
agency to ensure that the reliability emergency could be resolved 
while achieving maximum environmental protection. Should a verifiable 
reliability emergency arise in the future that may involve DOE's 
emergency authority, DOE will continue to coordinate with other 
agencies, as appropriate, to ensure that the emergency can be resolved 
in accordance with other applicable statutes and regulations. 

Thank you, again, for the opportunity to provide comment on the draft 
report. We look forward to receiving your final report. 

Sincerely, 

Signed by: 

Patricia A. Hoffman: 
Assistant Secretary: 
Office of Electricity Delivery and Energy Reliability: 
U.S. Department of Energy: 

[End of section] 

Appendix VII: Comments from the Environmental Protection Agency: 

United States Environmental Protection Agency: 
Deputy Administrator: 
Washington, D.C. 20460: 

July 5, 2012: 

Mr. Frank Rusco: 
Director, Natural Resources and Environment: 
U.S. Government Accountability Office: 
441 G Street, N.W., Room 2T23: 
Washington, D.C. 20548: 

Dear Mr. Rusco: 

On behalf of the U.S. Environmental Protection Agency, I thank you for 
your attention to the important issues surrounding implementation of 
the EPA's power plant rules and their effect on the electricity market 
and the power system. These rules will provide very substantial public 
health benefits for millions of Americans as well as important 
protections for the environment. The rules are achievable using 
technologies and practices that are widely available and are projected 
to have only a modest effect on electricity prices. In keeping with 
our strong track record in this area, the EPA continues to take great 
care, in close coordination with other federal agencies and outside 
stakeholders, to ensure these rules are implemented in a manner that 
does not adversely affect the reliability of the electric power system. 

At the outset, I want to acknowledge the U.S. Government 
Accountability Office's recommendation that the EPA work with the U.S. 
Department of Energy and the Federal Energy Regulatory Commission to 
further coordinate, formalize and document our ongoing activities to 
monitor industry's progress with regard to the implementation of EPA 
regulations and to share information among the three agencies. As 
explained in greater detail below, I am pleased to report that this 
effort is already underway. 

The GAO report covers four EPA rulemakings. Two of them (the cooling 
water intake rulemaking under section 316(b) of the Clean Water Act 
and the coal combustion residuals rulemaking under the Resource 
Conservation and Recovery Act) have been proposed and are still under 
revision in response to public comment (not yet final). The two final 
rules are the Cross State Air Pollution Rule and the Mercury and
Air Toxics Standards, promulgated under the Clean Air Act. Of these 
final rules, only MATS requires on a plant-by-plant basis significant 
investments in pollution control technologies within a limited time 
frame. As such, MATS is appropriately the focus of the GAO's report. 

The MATS rule prescribes standards under section 112 of the Clean Air 
Act to control emissions of mercury and other toxic air pollutants 
from coal-and oil-fired power plants, which collectively are among the 
largest sources of such pollution in the United States. MATS will 
substantially reduce emissions of pollutants that contribute to 
neurological damage, cancer, respiratory illnesses, premature death 
and other health risks, and it will produce important health benefits 
for millions of Americans, including children. The EPA estimates that 
beginning in 2016 these new standards will avert up to 11,000 
premature deaths, 4,700 heart attacks and 130,000 asthma attacks every 
year with monetized benefits far exceeding the estimated costs. 

More than half of the coal-fired capacity in the country already has 
modern pollution control technologies in use. Under MATS, facilities 
that do not already have adequate controls for mercury, acid gases and 
heavy metals will need to install or upgrade controls. The 
technologies to reduce these emissions are widely available and cost-
effective. However, while MATS does not require any plant to retire, 
some plants will make an economic decision to close rather than invest 
in pollution control, especially plants that are older and seldom used 
today. New capacity will come into the market, including demand 
resources. 

A variety of utilities and other stakeholders have expressed concerns 
that these retirements have the potential to impact electric 
reliability. The EPA has taken these concerns very seriously and, as 
explained below, has taken a number of steps to address them. It is 
essential, however, to make clear to readers that while the primary 
focus of the GAO report is the impact on grid reliability of the power 
sector's compliance with EPA regulations, EPA regulations are by no 
means the largest factor driving changes in the sector. 

The changes taking place in the electricity market today, independent 
of the EPA's rules, are remarkable and represent a significant shift 
from just a few years ago. These include a striking decline in natural 
gas prices, rising coal prices and reduced demand for electricity. In 
addition, a majority of coal plants in the fleet that have been in 
service for 40 years or longer, and many of these older plants are 
significantly less efficient than newer generation, resulting in very 
low utilization rates. As a result, the owners of some fossil fuel-
fired power plants appear to be finding that these plants' revenues no 
longer cover their operating costs, leading, in turn, to business 
decisions to retire these plants. 

These market drivers would have significant impacts even in the 
absence of the EPA's regulations. In fact, many observers think that 
the EPA's rules are relatively minor drivers of the important changes 
that are occurring today.[Footnote 1] A recent economic modeling study 
concluded: 

This analysis shows that the change between 2009 and 2011 in 
projections of natural gas supply and electricity demand has a much 
bigger effect on electricity prices, total generation, and generation 
by fuel than does the introduction of CSAPR [the Cross State
Air Pollution Rule] or MATS. Indeed for electricity prices, these 
secular changes drive effects that are generally more than 5 times 
greater than the effects of CSAPR or MATS. That multiple is even 
bigger when comparing the effects on electricity consumption and 
generation from coal.[Footnote 2] 

It is important for readers to understand the impact of the EPA's 
standards in this broader market context. For example, many recent 
announcements of "retirements" by utilities are actually merely 
accelerations of retirements that were already planned or may have 
occurred anyway in response to continuing shifts in market conditions. 
Notably, in many cases these utilities are seeking to close some of 
this capacity years in advance of the earliest MATS compliance 
deadline. 

We also think it is important to provide further context for some of 
the studies listed in the report that project retirements and other 
impacts, which the GAO examined to consider "the range of potential 
implications of the four regulations." While the EPA's regulatory 
analyses are based on peer-reviewed models, use accurate inputs 
reflecting the EPAs, rules and are transparent about their 
assumptions, not all of the other studies the report examined meet 
these standards. For example, many studies were based on the proposed 
version of the MATS rule and therefore do, not take into account the 
changes to the particulate matter standard which were made in the 
final rule, reducing likely costs for many firms. Similarly, the NERA 
study does not provide its electricity demand forecast, its natural 
gas and coal supply/price projections or details on treatment of key 
pollution control requirements, making it difficult to ensure that it 
is accurately reflecting the rules or current market dynamics. 

Although the EPA's rues are not the major driver of ongoing changes in 
the power sector, we have taken a number of steps, to assure that our 
rules do not interfere with electric reliability. Before MATS was 
finalized, the EPA and the DOE both conducted analyses of electric 
generation resources.[Footnote 3] Both the EPA's and the DOE's 
analyses demonstrate that the vast majority of, if not all, sources 
would be able to meet the MATS requirements within the time frames 
provided under the Clean Air Act. These studies indicated that large-
scale reliability problems as a consequence of MATS were extremely 
unlikely, consistent with the GAO's assessment of the available 
studies that "the actions power companies take in response to the four 
key EPA regulations are not likely to cause widespread reliability 
challenges." The EPA recognizes that these studies could not assure 
that there would not be localized reliability concerns and accordingly 
is focused on working with utilities and grid-planning organizations 
to help them anticipate and mitigate any such issues that may arise. 

In response to concerns about possible local-scale reliability impacts 
and consistent with a December 2011 Presidential Memorandum addressing 
MATS implementation, the EPA provided several flexibilities to assure 
that MATS implementation could proceed without compromising the 
stability of the electric power grid. The standards themselves contain 
several features to provide owner operators of power plants 
flexibility in how they are met.[Footnote 4] The EPA also provided 
significant flexibilities with regard to compliance timing. 

Under the Clean Air Act, permitting authorities (which generally are 
the states) can grant a fourth year to come into compliance — in 
addition to the three years provided to all sources — where necessary 
for the installation of controls. In the final rule, the EPA indicated 
that permitting authorities. should make this fourth year broadly 
available and described, in detail the wide range of situations where, 
we believe they can do so. These include situations in which 
additional time is needed to install pollution control equipment, to 
construct on-or off-site replacement power or to upgrade transmission 
to avert reliability problems. The EPA has reached out to states and 
permitting authorities to help ensure that the fourth year for 
compliance is broadly available. Based on this outreach, our 
understanding is that requests for the fourth year extension for air 
toxic standards have been handled well by states in the past, and we 
are not aware of any concerns. We have encouraged the states to 
continue processing these requests as they have done in the past. Both 
EPA headquarters and regional office staff members are available to 
quickly provide assistance and to answer any questions. As a result, 
the EPA estimates that sources generally will have until spring of 
2016 to comply — one year longer than our analysis indicates is 
necessary for most sources. 

In addition, the EPA is providing a clear pathway for units that are 
shown to be critical for electric reliability to obtain a schedule to 
achieve compliance within up to an additional year beyond the four 
years mentioned above. This pathway is set forth in a policy 
memorandum from the EPA's Office of Enforcement and Compliance 
Assurance.[Footnote 5] As stated above, the EPA believes there will be 
few, if any, situations in which this pathway will be needed. In 
addition, in the unlikely event that there are situations where 
sources that do not fall into any of these categories cannot come into 
compliance on a timely basis, the EPA will address them on a case-by-
case basis, at the appropriate time, to determine the appropriate 
response and resolution. This is consistent with its longstanding 
historical practice under the Clean Air Act. 

Consistent with the Presidential Memorandum issued on December 21, 
2011, the EPA is working closely with DOE and FERC, grid planning 
authorities, state public utility commissions and a range of other 
power-sector stakeholders to ensure early and coordinated planning and 
implementation of MATS requirements in a manner that maintains 
electric reliability. We are meeting regularly and frequently with 
FERC and DOE toward this end. We are also closely monitoring the 
implementation of MATS, primarily through regular communication with 
the Regional Transmission Organizations and other planning authorities 
that are responsible for grid planning and the assessment and 
mitigation of grid reliability concerns. We are holding regularly 
scheduled meetings between the three federal agencies and the RTOs, 
with a particular focus on the four key regions most affected by MATS. 
We are engaging in joint meetings with other planning authorities, the 
state regulatory agencies and the North American Electric Reliability 
Corporation and the NERC-affiliated regional entities, to monitor and 
address reliability issues that may arise. These have been productive 
exchanges that provide information that will help the EPA, the DOE and 
FERC to anticipate potential concerns well in advance, to better 
target our outreach and engagement with key stakeholders and to ensure 
that we are adequately prepared to address any reliability concerns 
that may arise. 

Again, we recognize and appreciate GAO's recommendation that the EPA 
continue to work with the DOE and FERC to further coordinate, 
formalize and document our ongoing monitoring and outreach activities. 
As outlined above, the agencies' coordination, outreach and monitoring 
efforts have grown progressively more extensive and regularized over 
time. Going forward, we expect to continue to develop these joint 
efforts as well as to further formalize and document them, consistent 
with your recommendations. 

In closing, I wish to express our appreciation for the professionalism 
of GAO staff during this inquiry. We look forward to the final report 
from the GAO. 

Sincerely, 

Signed by: 
Bob Perciasepe: 

Attachment: 

cc: Quindi Franco, Analyst-in-Charge, Government,Accountability Office: 
Bobbi Trent, GAO Liaison Team, EPA Office of the Chief Financial 
Officer: 
Mark T. Howard, GAO Liaison Team, EPA Office of the Chief Financial 
Officer: 

Footnotes: 

1. See for example: Susan Tierney, "Why Coal Plants Retire: Power 
Market Fundamentals as of 2012," The Analysis Group, February 6, 2012; 
James Bradbury, "U.S. Electricity Markets Increasingly Favor 
Alternatives to Coal" April 2012, and IHS
CERA, Market Briefing, "Sharply Lower Natural Gas Prices Reshape the 
US Power Supply Stack, " April 10, 2012. 

2. Burtraw et al., "Secular Trends, Environmental Regulations and 
Electricity Markets", RFF Discussion Paper (March 2012). 

3. Environmental Protection Agency (2011). "Resource Adequacy and 
Reliability in the IPM Projections for the MATS Rule" [hyperlink, 
http://www.epa.govittn/atw/utility/revised_resource_adequacy_tsd.pdf] 
Department of Energy (2011). "Resource Adequacy Implications of 
Forthcoming EPA Air Quality Regulations" [hyperlink, 
http://energy.govisites/prod/files/2011%20Air%20Quality%20Regulations%20
Report_A_120911.pdf]. 

4. For example, to meet the acid gas standard plants can meet a limit 
for the acid gases or they can meet an alternative standard for SO2 
that would provide equivalent reductions. Also, for all standards, 
existing plants can choose to meet an input standard expressed as 
pounds of pollutant emitted per unit of heat input or an output-based 
standard expressed as pounds of pollutant per unit of electricity 
generated. The standards themselves can be met by averaging among all 
the units in the same subcategory at a plant. Each unit does not have 
to meet the standard. Finally the standards are expressed as averages 
over time, rather than as limits not-to-be exceeded at any time. Other 
rules also have built in flexibilities that can help to avoid 
reliability issues. CSAPR allows owners and operators to determine 
their own emissions level subject to a limitation on total Electric 
Generating Utility emissions within that state; this market-based 
flexibility includes allowance trading across units within and between 
states. The 316(b) proposal grants permitting authorities flexibility 
to tailor compliance timelines to help avoid negative impacts on 
reliability. 

5. EPA Memorandum December 16, 2011. "The Environmental Protection 
Agency's Enforcement Response Policy For Use Of Clean Air Act Section 
I13(a) Administrative Orders In Relation To Electric Reliability And 
The Mercury and Air Toxics Standard" [hyperlink, 
http://www.epa.govicompliance/resources/policies/civiVerp/mats-
erp.pdf]. 

[End of section] 

Appendix VIII: GAO Contacts and Staff Acknowledgments: 

GAO Contacts: 

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

Staff Acknowledgments: 

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

[End of section] 

Footnotes: 

[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. 

[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. 

[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. 

[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). 

[8] EIA is a statistical agency within DOE that collects, analyzes, 
and disseminates independent information on energy issues. 

[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. 

[10] Generating 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. 

[11] EPA has set national ambient air quality standards for carbon 
monoxide, lead, NOx, ozone, particulate matter, and sulfur oxides. 

[12] States can replace federal implementation plans by developing and 
submitting for EPA approval state implementation plans that achieve 
the required amount of emissions reductions. 

[13] The 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. 

[14] CSAPR would cover certain fossil fuel electricity generating 
units with over 25 MW capacity. 

[15] A 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. 

[16] Specifically, 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. 

[17] The 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 coal-and oil-
fueled electric utility steam generating units by agreeing to sign a 
final regulation by the end of 2011. 

[18] Specifically, 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. 

[19] EPA'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 [hyperlink, 
http://www.epa.gov/compliance/resources/policies/civil/erp/mats-
rp.pdf]). 

[20] Some coal combustion residuals have beneficial uses; for example, 
they can be used in the manufacture of such construction materials as 
concrete or wallboard. According to EPA documentation, about 37 
percent of coal combustion residuals are used beneficially. EPA did 
not propose to regulate the beneficial use of coal combustion 
residuals, though some industry officials have expressed concerns that 
designating residuals as hazardous could negatively impact beneficial 
uses. 

[21] Furthermore, 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. 

[22] The 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. 

[23] These 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. 

[24] Using 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. 

[25] EPA first issued a regulation implementing section 316(b) in 
1976, but that regulation was struck down by a federal appeals court 
in 1979. EPA has issued two other regulations implementing section 
316(b) that are currently in effect: the Phase I regulation that 
governs new power plants and manufacturing facilities and the Phase 
III regulation that governs new offshore oil and gas facilities. 

[26] This 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. 

[27] We 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. 

[28] Independent 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. 

[29] Others involved in power company oversight may include municipal 
city councils for municipal power companies and boards of directors 
for cooperative power companies. 

[30] For 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. 

[31] The Public Utility Commission of Texas, rather than FERC, 
regulates the design and operation of the electricity markets in much 
of Texas. 

[32] Some 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. 

[33] According to FERC, RTOs have some authority to propose rule 
changes at FERC without broad stakeholder approval. 

[34] About 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. 

[35] Rates set by commissions may vary by customer classes (e.g., 
residential, commercial and industrial), as well as by the amount of 
electricity consumed. 

[36] In addition to the market-determined generation component of 
their electric bill, consumers in these areas also pay a regulated 
rate for transmission and distribution. 

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

[38] See 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). 

[39] GAO has ongoing work on the views of stakeholders of factors that 
may affect the future use of coal to generate electricity. 

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

[41] These states are: Arizona, California, Colorado, Connecticut, 
Delaware, Hawaii, Illinois, Iowa, Kansas, Maine, Maryland, 
Massachusetts, Michigan, Minnesota, Missouri, Montana, Nevada, New 
Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, 
Oregon, Pennsylvania, Rhode Island, Texas, Washington, West Virginia, 
and Wisconsin. 

[42] Under 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. 

[43] GAO, Air Emissions and Electricity Generation at U.S. Power 
Plants, [hyperlink, http://www.gao.gov/products/GAO-12-545R] 
(Washington, D.C.: Apr. 18, 2012). 

[44] Specifically, 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 appendix 
III.) 

[45] Coal 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. 

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

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

[48] Some 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 closed-cycle 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. 

[49] See 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. 

[50] Hugh 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). 

[51] See RFF (2012). 

[52] Information on planned retirements reflect publicly reported 
plans as identified by Ventyx. As plans may change, actual future 
retirements may differ from these plans. 

[53] Specifically, 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. 

[54] EPA 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. 

[55] EPA, Documentation for EPA Base Case v.4.10 Using the Integrated 
Planning Model, EPA#430R10010 (Washington, D.C.: August 2010) 
[hyperlink, 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) [hyperlink, 
http://www.epa.gov/airmarkets/progsregs/epa-pm/docs/suppdoc.pdf]. 

[56] These 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. 

[57] DOE, Resource Adequacy Implications of Forthcoming EPA Air 
Quality Regulations (December 2011). 

[58] EPA'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). 

[59] Modularization 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. 

[60] The 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). 

[61] The 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. 

[62] An 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. 

[63] These 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. 

[64] Under 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 [hyperlink, 
http://www.gao.gov/products/GAO-12-545R]. 

[65] RFF is a nonprofit and nonpartisan organization that conducts 
independent research on environmental, energy, natural resource and 
environmental health issues. 

[66] EPA 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. 

[67] EPA expressed concerns about some of the NERA study's assumptions 
and said its modeling was not sufficiently transparent. 

[68] While 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. 

[69] The 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. 

[70] Electricity 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. 

[71] NERC (2011). 

[72] Power companies take generating units off-line for regularly 
scheduled maintenance that often lasts about 4 weeks. 

[73] States 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. 

[74] See PJM, "Future Deactivations (as of May 30, 2012)," [hyperlink, 
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. 

[75] There 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. 

[76] Georgia 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. 

[77] According 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. 

[78] GAO, Electricity Markets: Consumers Could Benefit from Demand 
Programs, but Challenges Remain, [hyperlink, 
http://www.gao.gov/products/GAO-04-844] (Washington D.C.: Aug. 13, 
2004). 

[79] If 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. 

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

[81] Because 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. 

[82] These administrative orders are authorized by section 113(a) of 
the Clean Air Act and, by statute, cannot last for longer than a year 
or be renewed. 

[83] This 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 [hyperlink, 
http://www.epa.gov/compliance/resources/policies/civil/erp/mats-
erp.pdf]. 

[84] According to EPA officials and two stakeholders, provided that 
EPA establishes a well-documented record supporting its decision to 
issue an administrative order, the risk of a successful citizens' suit 
can be minimized. 

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

[86] Specifically, 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. 

[87] In 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. 

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

[89] Furthermore, 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. 

[90] An 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. 

[91] See 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) [hyperlink, 
http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=6053&CalType=%20&
CalendarID=116&Date=&View=Listview]. 

[92] Specifically, 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. 

[93] GAO, Risk Management: Further Refinements Needed to Assess Risks 
and Prioritize Protective Measures at Ports and Other Critical 
Infrastructure, [hyperlink, http://www.gao.gov/products/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. 

[94] Some system planners--including power companies and RTOs--and 
state regulators have begun collecting information that may relate to 
these topics. 

[95] FERC 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. 

[96] GAO, Live Animal Imports: Agencies Need Better Collaboration to 
Reduce the Risk of Animal-Related Diseases, [hyperlink, 
http://www.gao.gov/products/GAO-11-9] (Washington, D.C.: Nov. 8, 
2010); GAO, National Security: Key Challenges and Solutions to 
Strengthen Interagency Collaboration, [hyperlink, 
http://www.gao.gov/products/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, [hyperlink, http://www.gao.gov/products/GAO-08-251] 
(Washington, D.C.: Apr. 16, 2008). 

[97] With the exception of Kentucky, Missouri, and Pennsylvania, we 
spoke with both electricity and environmental regulators in these 
states. 

[End of section] 

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