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United States Government Accountability Office: 
GAO: 

Report to the Chairman, Committee on Commerce, Science, and 
Transportation, U.S. Senate: 

October 2012: 

Electricity: 

Significant Changes Are Expected in Coal-Fueled Generation, but Coal 
is Likely to Remain a Key Fuel Source: 

GAO-13-72: 

GAO Highlights: 

Highlights of GAO-13-72, a report to the Chairman, Committee on 
Commerce, Science and Transportation, U.S. Senate. 

Why GAO Did This Study: 

Coal is a key domestic fuel source and an important contributor to the 
U.S. economy. Most coal produced in the United States is used to 
generate electricity. In 2011, 1,387 coal-fueled electricity 
generating units produced about 42 percent of the nation's 
electricity. After decades of growth, U.S. coal production and 
consumption have fallen, primarily due to declines in the use of coal 
to generate electricity. 

According to the Environmental Protection Agency (EPA), using coal to 
generate electricity is associated with health and environmental 
concerns such as emissions of sulfur dioxide, a pollutant linked to 
respiratory illnesses, and carbon dioxide, a greenhouse gas linked to 
climate change. In response to recent environmental regulations and 
changing market conditions, such as the recent decrease in the price 
of natural gas, power companies may retrofit some units by installing 
controls to reduce pollutants. They may also retire some units, which 
could affect the coal fleet’s generating capacity––the ability to 
generate electricity––and the amount of electricity generated from 
coal. 

GAO was asked to examine (1) how the fleet of coal-fueled electricity 
generating units may change in the future in terms of its generating 
capacity and other aspects and (2) the future use of coal to generate 
electricity in the United States and key factors that could affect it. 
GAO conducted a statistical analysis of plans for retiring coal-fueled 
units, interviewed stakeholders, and reviewed information on industry 
plans and long-term forecasts by EIA and others. GAO is not making any 
recommendations in this report. 

What GAO Found: 

Retirements of older units, retrofits of existing units with pollution 
controls, and the construction of some new coal-fueled units are 
expected to significantly change the coal-fueled electricity 
generating fleet, making it capable of emitting lower levels of 
pollutants than the current fleet but reducing its future electricity 
generating capacity. Two broad trends are affecting power companies' 
decisions related to coal-fueled generating units—recent environmental 
regulations and changing market conditions, such as the recent 
decrease in the price of natural gas. Regarding retirements, forecasts 
GAO reviewed based on current policies project that power companies 
may retire 15 to 24 percent of coal-fueled generating capacity by 
2035––an amount consistent with GAO's statistical analysis. To assess 
the types of units that may be retired, in its statistical analysis, 
GAO analyzed data on power companies that have announced plans to 
retire coal-fueled units. Among other things, GAO found that these 
power companies are more likely to retire units that are older, 
smaller, and more polluting. For example, the units companies plan to 
retire emitted an average of twice as much sulfur dioxide per unit of 
fuel used in 2011 as units that companies do not plan to retire. GAO 
then examined units owned by companies that have not announced any 
retirements and, based on the characteristics of those units, 
estimated the number and generating capacity of other units companies 
may consider retiring. In its statistical analysis, GAO identified a 
total of 15 to 18 percent of coal-fueled capacity that power companies 
either plan to retire or that GAO estimated may retire based on the 
characteristics of the unit—an amount consistent with the forecasts 
GAO reviewed. Regarding retrofits, the coal-fueled generating fleet 
may also become less polluting in the future as power companies 
install controls on many remaining units. Regarding new coal-fueled 
units, these are likely to be less polluting as they must incorporate 
advanced technologies to reduce emissions of regulated pollutants. 
Coal-fueled capacity may decline as less capacity is expected to be 
built than is expected to retire. 

According to stakeholders and three long-term forecasts GAO reviewed, 
coal is generally expected to remain a key fuel source for U.S. 
electricity generation in the future, but coal’s share as a source of 
electricity may continue to decline. For example, in its forecast 
based on current policies, the Energy Information Administration (EIA) 
forecasts that the share of coal-fueled electricity generation will 
decline from 42 percent in 2011 to 38 percent in 2035. Available 
information suggests that the future U.S. use of coal may be 
determined by several key factors, including the price of natural gas 
and environmental regulations. For example, available information 
suggests that the price of coal compared with other fuel sources will 
influence how economically attractive it is to use coal to generate 
electricity. EIA assessed several scenarios of future fuel prices and 
forecasts that coal’s share of U.S. electricity generation will fall 
to 30 percent in 2035 if natural gas prices are low or 40 percent if 
natural gas prices are high. In addition, some stakeholders told GAO 
that the future use of coal could be significantly affected if 
existing environmental regulations become more stringent or if 
additional environmental regulations are issued. For example, EIA 
forecasts that two hypothetical future policies that reduce carbon 
dioxide emissions from the electricity sector by 46 percent and 76 
percent would result in coal's share of U.S. electricity generation 
falling to 16 and 4 percent in 2035, respectively. 

View [hyperlink, http://www.gao.gov/products/GAO-13-72]. For more 
information, contact Frank Rusco at (202) 512-3841 or ruscof@gao.gov. 

[End of section] 

Contents: 

Letter: 

Background: 

Retirements, Retrofits, and New Construction May Result in a Smaller 
but Cleaner Coal-Fueled Electricity Generating Fleet: 

Coal Likely to Remain a Key Fuel Source, but Future Use May Be 
Affected by Fuel Prices, Environmental Regulations, and Other Factors: 

Agency Comments and Our Evaluation: 

Appendix I: Analysis of Characteristics of Coal-Fueled Generating 
Units That Power Companies Plan to Retire: 

Methodology: 

Results: 

Analysis Indicates Units Power Companies Likely to Consider Retiring: 

Limitations and Alternative Model Specifications: 

Appendix II: Description of Selected Scenarios and Forecasts: 

Appendix III GAO Contact and Staff Acknowledgments: 

Related GAO Products: 

Tables: 

Table 1: Results of EIA Alternate Fuel Price Scenarios: 

Table 2: Regression Results of Characteristics Associated with Planned 
Coal-Fueled Unit Retirements-Dependent Variable Is the Probability of 
a Unit Retirement Announcement: 

Table 3: Effect of 10% Change in a Variable Value on the Probability 
of an Average Unit's Planned Retirement When Owned by a Power Company 
in a Restructured Marked: 

Table 4: Effect of 10% Change in a Variable Value on the Probability 
of an Average Unit's Planned Retirement When Owned by a Traditionally 
Regulated Power Company: 

Table 5: Coal-Fueled Units That Companies May Consider for Retirement 
by 2020: 

Table 6: Regression Results of Characteristics Associated with Planned 
Coal-Fueled Unit Retirements Using Clustered Standard Errors: 

Table 7: Regression Results of Characteristics Associated with Planned 
Coal-Fueled Unit Retirements Including Adjusted Marginal Cost and 
Interaction Term: 

Table 8: Description of EIA, IHS Global Insight, and IEA Scenarios and 
Forecasts: 

Figures: 

Figure 1: Coal Production and Employment, 1960-2011: 

Figure 2: Electricity Generation from Coal, 1960-2010: 

Figure 3: U.S. Coal Exports by Destination, 2001-2011: 

Figure 4: Capacity of Coal-Fueled Units by Year of First Commercial 
Operation and Planned Retirements: 

Figure 5: Number of Coal-Fueled Electricity Generating Units by 
Capacity Category: 

Figure 6: Number of Coal-Fueled Electricity Generating Units by 2011 
SO2 Emissions Rate: 

Figure 7: Capacity of Planned Coal-Fueled Electricity Generating Units 
by Status, as of July 26, 2012: 

Figure 8: Actual 2011 and Projected 2035 Coal-Fueled Electricity 
Generating Capacity: 

Figure 9: EIA's Reference Scenario Projections of Electricity 
Generation by Fuel: 

Figure 10: Actual 2010 and EIA's Reference Scenario Projected 2035 
Coal Production by Region: 

Figure 11: Actual and Projected Coal and Natural Gas Prices: 

Abbreviations: 

Btu: British thermal unit: 

CO2: carbon dioxide: 

EIA: Energy Information Administration: 

EPA: Environmental Protection Agency: 

IEA: International Energy Agency: 

MW: megawatt: 

MWh: megawatt-hour: 

NOx: nitrogen oxides: 

SO2: sulfur dioxide: 

[End of section] 

United States Government Accountability Office: Washington, DC 20548: 

October 29, 2012: 

The Honorable John D. Rockefeller IV: 
Chairman: 
Committee on Commerce, Science, and Transportation: 
United States Senate: 

Dear Mr. Chairman: 

Coal is a key domestic fuel source and an important contributor to the 
U.S. economy. The United States has the largest recoverable coal 
reserves in the world, according to the Energy Information 
Administration (EIA).[Footnote 1] In 2011, about 86,200 workers around 
the country produced more than 1 billion tons of coal, and more than 
90 percent of this coal was used to generate electricity in the United 
States.[Footnote 2] Also in 2011, there were 1,387 coal-fueled 
electricity generating units with a total of 317,469 megawatts (MW) of 
capacity--a measure of the ability to generate electricity[Footnote 
3]--about 30 percent of total generating capacity in the United 
States. These coal-fueled units generated 42 percent of the nation's 
electricity in 2011.[Footnote 4] After decades of growth--peaking in 
2008--U.S. coal production has fallen, primarily due to declines in 
the use of coal to generate electricity. Some stakeholders expressed 
concern, if this trend were to continue, about the implications on 
electricity systems, communities, and economies that rely on coal 
mining and coal-fueled electricity. 

Using coal to generate electricity has been associated with human 
health and environmental concerns by the Environmental Protection 
Agency (EPA), the primary federal agency responsible for implementing 
many of the nation's environmental laws. For example, according to EPA 
data, coal-fueled 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. EPA recently 
proposed or finalized several regulations, as required or authorized, 
that aim to address certain health or environmental impacts associated 
with coal-fueled electricity generating units. In response to these 
regulations, power companies might retrofit some units by installing 
controls to reduce pollutants or by taking other steps to reduce 
adverse impacts.[Footnote 5] When it is not economic to take these 
actions, power companies may retire some units, which could affect 
coal-fueled generating capacity and the amount of electricity actually 
generated from coal. We recently reported on the price and reliability 
implications of key recent EPA regulations.[Footnote 6] In addition, 
according to EPA data, coal-fueled electricity generating units emit 
large quantities of carbon dioxide (CO2). As we have previously 
reported, compared with natural gas-fueled units, coal-fueled units 
produced, on average, over twice as much CO2 per unit of electricity 
produced as natural gas units in 2010.[Footnote 7] The National 
Research Council[Footnote 8] has stated that emissions of CO2 and 
other greenhouse gases are linked to climate change. There have been a 
number of legislative proposals in Congress, regulatory action by EPA, 
and actions at the state and local levels aiming to reduce CO2 
emissions. 

You asked us to examine the future use of coal to generate 
electricity. Our objectives for this report were to examine what 
available information indicates about: (1) how the nation's fleet of 
coal-fueled electricity generating units may change in the future in 
terms of its generating capacity and other aspects and (2) the use of 
coal to generate electricity in the United States in the future and 
key factors that could affect it. 

To examine how the coal-fueled generating fleet may change, we used 
data from Ventyx Velocity Suite, a proprietary database containing 
consolidated energy and emissions data from EIA, EPA, and other 
sources. We used data as of July 27, 2012, to describe characteristics 
of coal-fueled electricity generating units and to provide information 
on power companies' plans to retire coal-fueled units and build new 
ones. Such information reflects publicly reported plans as identified 
by Ventyx. As plans may change, the actual number and characteristics 
of future retirements and new construction of coal-fueled units may 
differ from what is represented in Ventyx as of July 2012. To assess 
the types of units that may be retired, we carried out a statistical 
analysis of units owned by power companies that have announced plans 
to retire coal-fueled units. We analyzed various characteristics 
including characteristics of the unit (i.e., size and age) and the 
characteristics of the power company that owns the unit (i.e., whether 
it is traditionally regulated or operates in a restructured market). 
[Footnote 9] We then examined units owned by companies that have not 
announced any planned retirements in order to estimate how many of 
those units companies may consider retiring. Our statistical analysis 
did not examine the amount of electricity that may be generated at 
coal-fueled units in the future. Appendix I provides further 
information about our statistical analysis. To provide information 
about the use of coal to generate electricity in the future and key 
factors that could affect it, we reviewed forecasts from EIA, the 
International Energy Agency (IEA)[Footnote 10] and IHS Global Insight, 
[Footnote 11] and summarized projections of coal-fueled electricity 
generation under different scenarios. Appendix II summarizes the 
scenarios we examined. While long-term forecasts are subject to 
inherent uncertainties, we found the EIA, IEA and IHS Global Insight 
forecasts to be reasonable for describing what is known about the 
potential future use of coal to generate electricity. To respond to 
both objectives, we reviewed available literature, including studies 
by federal agencies and research organizations, and summarized the 
results of semistructured interviews with a nonprobability sample of 
36 stakeholders. Stakeholders included representatives from power 
companies, a coal company, and nongovernmental organizations, and 
officials from federal and state agencies. We selected these 
stakeholders to be broadly representative of differing perspectives on 
these issues based on recommendations from agencies and industry 
associations, along with other information. Because we used a 
nonprobability sample, the views of these stakeholders are not 
generalizable to all potential stakeholders, but they provide 
illustrative examples of views. To provide information on recent 
electricity industry trends, we summarized historical data from EIA. 
To assess the reliability of Ventyx and EIA historical data, we 
reviewed existing documentation, interviewed Ventyx and EIA staff, 
consulted with agency 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 and EIA data to 
be sufficiently reliable for the purposes of this report. Some numbers 
in this report have been rounded. 

We conducted our work from July 2011 to October 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: 

Because of its abundance and historically low cost, coal is an 
important fuel source in the United States, accounting for about 20 
percent of total energy use in 2011. Nearly all coal consumed in the 
United States is produced domestically, and coal represents about 29 
percent of all domestically produced energy. U.S. coal production 
generally increased since 1960 and reached its highest level in 2008. 
Advancements in mining technology and a shift to using surface mines 
to a greater extent than underground mines has boosted coal's overall 
productivity and enabled production to increase even as the number of 
workers decreased. In 2011, half as many workers produced 24 percent 
more coal than in 1985, as shown in figure 1. Data from the Bureau of 
Labor Statistics indicate that about 86,200 people were employed in 
coal mining in the United States in 2011. 

Figure 1: Coal Production and Employment, 1960-2011: 

[Refer to PDF for image: multiple line graph] 

Year: 1960; 
Production (million tons): 434. 

Year: 1961; 
Production (million tons): 420. 

Year: 1962; 
Production (million tons): 439. 

Year: 1963; 
Production (million tons): 477. 

Year: 1964; 
Production (million tons): 504. 

Year: 1965; 
Production (million tons): 527. 

Year: 1966; 
Production (million tons): 547. 

Year: 1967; 
Production (million tons): 565. 

Year: 1968; 
Production (million tons): 557. 

Year: 1969; 
Production (million tons): 571. 

Year: 1970; 
Production (million tons): 613. 

Year: 1971; 
Production (million tons): 561. 

Year: 1972; 
Production (million tons): 602. 

Year: 1973; 
Production (million tons): 599. 

Year: 1974; 
Production (million tons): 610. 

Year: 1975; 
Production (million tons): 655. 

Year: 1976; 
Production (million tons): 685. 

Year: 1977; 
Production (million tons): 697. 

Year: 1978; 
Production (million tons): 670. 

Year: 1979; 
Production (million tons): 781. 

Year: 1980; 
Production (million tons): 830. 

Year: 1981; 
Production (million tons): 824. 

Year: 1982; 
Production (million tons): 838. 

Year: 1983; 
Production (million tons): 782. 

Year: 1984; 
Production (million tons): 896. 

Year: 1985; 
Production (million tons): 884; 
Employment: 174,000. 

Year: 1986; 
Production (million tons): 890; 
Employment: 163,000. 

Year: 1987; 
Production (million tons): 919; 
Employment: 150,000. 

Year: 1988; 
Production (million tons): 950; 
Employment: 139,000. 

Year: 1989; 
Production (million tons): 981; 
Employment: 133,000. 

Year: 1990; 
Production (million tons): 1,029; 
Employment: 136,000. 

Year: 1991; 
Production (million tons): 996; 
Employment: 126,000. 

Year: 1992; 
Production (million tons): 998; 
Employment: 118,000. 

Year: 1993; 
Production (million tons): 945; 
Employment: 100,000. 

Year: 1994; 
Production (million tons): 1,034; 
Employment: 104,000. 

Year: 1995; 
Production (million tons): 1,033; 
Employment: 97,000. 

Year: 1996; 
Production (million tons): 1,064; 
Employment: 91,000. 

Year: 1997; 
Production (million tons): 1,090; 
Employment: 89,000. 

Year: 1998; 
Production (million tons): 1,118; 
Employment: 85,000. 

Year: 1999; 
Production (million tons): 1,100; 
Employment: 79,000. 

Year: 2000; 
Production (million tons): 1,074; 
Employment: 72,000. 

Year: 2001; 
Production (million tons): 1,128; 
Employment: 74,000. 

Year: 2002; 
Production (million tons): 1,094; 
Employment: 74,000. 

Year: 2003; 
Production (million tons): 1,072; 
Employment: 70,000. 

Year: 2004; 
Production (million tons): 1,112; 
Employment: 71,000. 

Year: 2005; 
Production (million tons): 1,131; 
Employment: 74,000. 

Year: 2006; 
Production (million tons): 1,163; 
Employment: 78,000. 

Year: 2007; 
Production (million tons): 1,147; 
Employment: 77,000. 

Year: 2008; 
Production (million tons): 1,172; 
Employment: 81,000. 

Year: 2009; 
Production (million tons): 1,075; 
Employment: 82,000. 

Year: 2010; 
Production (million tons): 1,085; 
Employment: 81,000. 

Year: 2011; 
Production (million tons): 1,094; 
Employment: 86,000. 

Source: GAO analysis of EIA and Bureau of Labor Statistics data. 

[End of figure] 

In the United States, coal is primarily used to generate electricity-- 
over 90 percent of coal was used to generate about 42 percent of 
electricity in 2011. The amount of electricity generated using coal 
has generally increased since the 1960s, but decreased recently due to 
a combination of a decline in overall electricity demand, shifts in 
the relative prices of fuels, and other reasons. (See figure 2.) 
Meanwhile, coal's share of total electricity generation has fluctuated 
over time. EIA has stated that several factors, including low oil 
prices during the late 1960s--which served to increase electricity 
generation from oil--and the oil price shocks of the 1970s have 
influenced the mix of fuel sources used to produce electricity. 

Figure 2: Electricity Generation from Coal, 1960-2010: 

Year: 1960; 
Net generation from coal: 0.40 billion MWh; 
Share of total generation from coal: 53.1%. 

Year: 1961; 
Net generation from coal: 0.42 billion MWh; 
Share of total generation from coal: 52.9%. 

Year: 1962; 
Net generation from coal: 0.45 billion MWh; 
Share of total generation from coal: 52.5%. 

Year: 1963; 
Net generation from coal: 0.50 billion MWh; 
Share of total generation from coal: 53.7%. 

Year: 1964; 
Net generation from coal: 0.53 billion MWh; 
Share of total generation from coal: 53.3%. 

Year: 1965; 
Net generation from coal: 0.57 billion MWh; 
Share of total generation from coal: 53.9%. 

Year: 1966; 
Net generation from coal: 0.61 billion MWh; 
Share of total generation from coal: 53.5%. 

Year: 1967; 
Net generation from coal: 0.63 billion MWh 
Share of total generation from coal: 51.8%. 

Year: 1968; 
Net generation from coal: 0.68 billion MWh; 
Share of total generation from coal: 51.4%. 

Year: 1969; 
Net generation from coal: 0.71 billion MWh; 
Share of total generation from coal: 48.8%. 

Year: 1970; 
Net generation from coal: 0.70 billion MWh; 
Share of total generation from coal: 45.9%. 

Year: 1971; 
Net generation from coal: 0.71 billion MWh; 
Share of total generation from coal: 44.1%. 

Year: 1972; 
Net generation from coal: 0.77 billion MWh; 
Share of total generation from coal: 44.0%. 

Year: 1973; 
Net generation from coal: 0.85 billion MWh; 
Share of total generation from coal: 45.5%. 

Year: 1974; 
Net generation from coal: 0.83 billion MWh; 
Share of total generation from coal: 44.3%. 

Year: 1975; 
Net generation from coal: 0.85 billion MWh; 
Share of total generation from coal: 44.4%. 

Year: 1976; 
Net generation from coal: 0.94 billion MWh; 
Share of total generation from coal: 46.3%. 

Year: 1977; 
Net generation from coal: 0.99 billion MWh; 
Share of total generation from coal: 46.3%. 

Year: 1978; 
Net generation from coal: 0.98 billion MWh; 
Share of total generation from coal: 44.2%. 

Year: 1979; 
Net generation from coal: 1.16 billion MWh; 
Share of total generation from coal: 50.7%. 

Year: 1980; 
Net generation from coal: 1.08 billion MWh; 
Share of total generation from coal: 47.8%. 

Year: 1981; 
Net generation from coal: 1.20 billion MWh; 
Share of total generation from coal: 52.4%. 

Year: 1982; 
Net generation from coal: 1.19 billion MWh; 
Share of total generation from coal: 53.1%. 

Year: 1983; 
Net generation from coal: 1.26 billion MWh; 
Share of total generation from coal: 54.4%. 

Year: 1984; 
Net generation from coal: 1.34 billion MWh; 
Share of total generation from coal: 55.5%. 

Year: 1985; 
Net generation from coal: 1.40 billion MWh; 
Share of total generation from coal: 56.7%. 

Year: 1986; 
Net generation from coal: 1.39 billion MWh; 
Share of total generation from coal: 55.6%. 

Year: 1987; 
Net generation from coal: 1.46 billion MWh; 
Share of total generation from coal: 56.8%. 

Year: 1988; 
Net generation from coal: 1.54 billion MWh; 
Share of total generation from coal: 56.9%. 

Year: 1989; 
Net generation from coal: 1.58 billion MWh; 
Share of total generation from coal: 53.6%. 

Year: 1990; 
Net generation from coal: 1.59 billion MWh; 
Share of total generation from coal: 52.7%. 

Year: 1991; 
Net generation from coal: 1.59 billion MWh; 
Share of total generation from coal: 51.9%. 

Year: 1992; 
Net generation from coal: 1.62 billion MWh; 
Share of total generation from coal: 52.8%. 

Year: 1993; 
Net generation from coal: 1.69 billion MWh; 
Share of total generation from coal: 53.1%. 

Year: 1994; 
Net generation from coal: 1.69 billion MWh; 
Share of total generation from coal: 52.3%. 

Year: 1995; 
Net generation from coal: 1.71 billion MWh; 
Share of total generation from coal: 51.2%. 

Year: 1996; 
Net generation from coal: 1.80 billion MWh; 
Share of total generation from coal: 52.3%. 

Year: 1997; 
Net generation from coal: 1.85 billion MWh; 
Share of total generation from coal: 53.0%. 

Year: 1998; 
Net generation from coal: 1.87 billion MWh; 
Share of total generation from coal: 51.9%. 

Year: 1999; 
Net generation from coal: 1.88 billion MWh; 
Share of total generation from coal: 51.1%. 

Year: 2000; 
Net generation from coal: 1.97 billion MWh; 
Share of total generation from coal: 51.9%. 

Year: 2001; 
Net generation from coal: 1.90 billion MWh; 
Share of total generation from coal: 51.1%. 

Year: 2002; 
Net generation from coal: 1.93 billion MWh; 
Share of total generation from coal: 50.3%. 

Year: 2003; 
Net generation from coal: 1.97 billion MWh; 
Share of total generation from coal: 51.1%. 

Year: 2004; 
Net generation from coal: 1.98 billion MWh; 
Share of total generation from coal: 50.1%. 

Year: 2005; 
Net generation from coal: 2.01 billion MWh; 
Share of total generation from coal: 49.9%. 

Year: 2006; 
Net generation from coal: 1.99 billion MWh; 
Share of total generation from coal: 49.2%. 

Year: 2007; 
Net generation from coal: 2.02 billion MWh; 
Share of total generation from coal: 48.7%. 

Year: 2008; 
Net generation from coal: 1.99 billion MWh; 
Share of total generation from coal: 48.4%. 

Year: 2009; 
Net generation from coal: 1.76 billion MWh; 
Share of total generation from coal: 44.7%. 

Year: 2010; 
Net generation from coal: 1.85 billion MWh; 
Share of total generation from coal: 45.1%. 

Source: GAO analysis of EIA data. 

Note: Net generation excludes electricity generation that is used 
internally for plant operations. 

[End of figure] 

Two broad trends--recent environmental regulations and changing market 
conditions--are affecting power companies' decisions related to coal-
fueled electricity generating units. Regarding environmental 
regulations, as we have previously reported, since June 2010, EPA 
proposed or finalized several regulations that would reduce certain 
adverse health or environmental impacts, including impacts associated 
with coal-fueled electricity generating units.[Footnote 12] These 
regulations have potentially significant implications for public 
health and the environment. One of the most significant regulations in 
terms of EPA's estimated benefits and costs, EPA's Mercury and Air 
Toxics Standards, establishes emissions limitations on mercury and 
other toxic pollutants. 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. EPA estimates that its 
finalized regulation would reduce mercury emissions from coal-fueled 
electricity generating units by 75 percent, as well as reduce SO2 and 
other emissions. EPA estimated the benefits of this one regulation 
would be $39 to $96 billion with costs of $10.2 billion in 2016 (in 
2011 year dollars). The requirements and deadlines these regulations 
may establish for generating units are uncertain. In particular, 
several regulations have not been finalized, and finalized regulations 
could be subject to legal challenges that result in changes. For 
example, EPA finalized the Cross-State Air Pollution Rule in August 
2011. The regulation would have required reductions of certain 
emissions of air pollutants in 28 states because some of these 
pollutants may travel in the atmosphere and impact air quality in 
other states. The U.S. Court of Appeals for the D.C. Circuit recently 
struck down the regulation, and EPA has asked the full court to rehear 
the case, creating uncertainty as to what may be required from 
generating units in the future to address such emissions.[Footnote 13] 
In response to these regulations, power companies might retrofit 
generating units with controls to reduce pollutants and, when it is 
not economic to retrofit, may retire some generating units. 

Regarding broader market conditions, important market drivers have 
been weighing on the viability of coal-fueled electricity generating 
units. Key among these has been the recent decrease in the price of 
natural gas, which has made it more attractive for power companies to 
build new gas-fueled electricity generating units and to utilize 
existing units more. In addition, slow expected growth in demand for 
electricity in some areas has decreased the need for new generating 
units. Power companies may weigh the costs of any needed investments 
compared with the benefits of continuing to generate electricity at a 
particular unit. When the costs outweigh the benefits, a power company 
may decide to retire a unit rather than continue to operate the unit 
or install new pollution control equipment. 

The majority of coal produced in the United States is used 
domestically, though exports represent a small but recently growing 
fraction of U.S. coal production. In 2010, the United States exported 
82 million tons of coal, which accounted for 8 percent of total 
production. As shown in figure 3, coal exports to European and Asian 
markets represented 76 percent of total U.S. coal exports in 2011. In 
2011, total coal exports were up 31 percent compared with 2010, 
reaching 107 million tons, due largely to rising exports to Europe and 
Asia. This was the highest level of exports since 1991. In 2011, 35 
percent of U.S. coal exports were of the types of coal typically used 
to produce electricity, the remainder were of metallurgical coals used 
in industrial processes, such as steelmaking. 

Figure 3: U.S. Coal Exports by Destination, 2001-2011: 

[Refer to PDF for image: stacked vertical bar graph] 

U.S. Coal Exports: 

Year: 2001; 
Europe: 20.8 million tons; 
Asia: 3.2 million tons; 
North America: 18.5 million tons; 
South America: 4.8 million tons; 
Africa Australia and Oceania: 1.2 million tons. 

Year: 2002; 
Europe: 15.6 million tons; 
Asia: 1.7 million tons; 
North America: 17.6 million tons; 
South America: 3.8 million tons; 
Africa Australia and Oceania: 0.9 million tons. 

Year: 2003; 
Europe: 15.1 million tons; 
Asia: 0.3 million tons; 
North America: 21.9 million tons; 
South America: 3.8 million tons; 
Africa Australia and Oceania: 1.9 million tons. 

Year: 2004; 
Europe: 15.2 million tons; 
Asia: 7.5 million tons; 
North America: 18.8 million tons; 
South America: 4.8 million tons; 
Africa Australia and Oceania: 1.7 million tons. 

Year: 2005; 
Europe: 18.8 million tons; 
Asia: 5.1 million tons; 
North America: 20.6 million tons; 
South America: 4.6 million tons; 
Africa Australia and Oceania: 0.9 million tons. 

Year: 2006; 
Europe: 20.8 million tons; 
Asia: 2.0 million tons; 
North America: 20.5 million tons; 
South America: 4.9 million tons; 
Africa Australia and Oceania: 1.4 million tons. 

Year: 2007; 
Europe: 27.1 million tons; 
Asia: 1.2 million tons; 
North America: 19.1 million tons; 
South America: 7.2 million tons; 
Africa Australia and Oceania: 4.5 million tons. 

Year: 2008; 
Europe: 40.3 million tons; 
Asia: 5.3 million tons; 
North America: 24.4 million tons; 
South America: 7.7 million tons; 
Africa Australia and Oceania: 3.9 million tons. 

Year: 2009; 
Europe: 30.1 million tons; 
Asia: 6.5 million tons; 
North America: 12.1 million tons; 
South America: 8.6 million tons; 
Africa Australia and Oceania: 1.8 million tons. 

Year: 2010; 
Europe: 38.2 million tons; 
Asia: 17.9 million tons; 
North America: 13.4 million tons; 
South America: 9.5 million tons; 
Africa Australia and Oceania: 2.6 million tons. 

Year: 2011; 
Europe: 53.9 million tons; 
Asia: 27.5 million tons; 
North America: 10.2 million tons; 
South America: 11.2 million tons; 
Africa Australia and Oceania: 4.0 million tons. 

Source: EIA. 

[End of figure] 

To better understand the potential future of the coal and electricity 
industries, the federal government, private companies, and others use 
models to project future industry conditions, including the future use 
of coal. For example, EIA, IEA, and IHS Global Insight produce long-
term projections of electricity generation and generation from coal. 
[Footnote 14] Because the future depends on a multitude of factors 
that are difficult to predict, EIA assesses various scenarios with 
different assumptions about future conditions to better understand the 
range of potential future outcomes. For example, EIA's primary 
scenario, called its "reference" scenario, is a business-as-usual 
estimate based on existing policies, known technology, and current 
technological and demographic trends. Additional scenarios make 
different assumptions about fuel prices, economic conditions, and 
government policies, among other things. Some of these scenarios are 
especially relevant to the question of coal's future, because they 
address factors currently affecting the industry, such as the prices 
of coal and natural gas--a fuel that competes with coal--and possible 
future policies to address climate change. Appendix II presents 
further information about the major assumptions behind these forecasts 
and scenarios. 

Retirements, Retrofits, and New Construction May Result in a Smaller 
but Cleaner Coal-Fueled Electricity Generating Fleet: 

The nation's fleet of coal-fueled electricity generating units may 
have less total generating capacity in the future, and the fleet may 
be capable of emitting lower levels of pollutants, according to 
available information. These changes will be driven by industry plans 
to retire a significant number of units, install pollution control 
equipment on others, and build a few, new coal-fueled units that may 
emit lower levels of pollutants than the current fleet's average 
emissions. 

Power Companies Are Planning to Retire a Significant Number of Older, 
Smaller, More Polluting Units: 

According to forecasts we reviewed, power companies may retire a 
significant number of coal-fueled units in the future. In its 
reference scenario reflecting current policies, EIA projects that 
power companies may retire 49,000 MW of coal-fueled capacity from 2011 
through 2035 (i.e., 15 percent of coal-fueled capacity in 2011). IHS 
Global Insight projects that power companies may retire 76,476 MW of 
capacity from 2011 through 2035 (i.e., 24 percent of coal-fueled 
capacity in 2011). 

Our statistical analysis of Ventyx data on announced retirement plans 
indicates that, among other things, companies are planning to retire 
units that are older, smaller, and more polluting. To assess the types 
of units that may be retired, we analyzed data on current power 
company plans to retire coal-fueled units. According to Ventyx data, 
power companies have already reported plans to retire 174 coal-fueled 
units with a total 30,447 MW net summer capacity through 2020--which 
accounted for 10 percent of coal-fueled capacity in 2011.[Footnote 15] 
As we have previously reported, this would be significantly more 
retirements than have occurred in the past--almost twice as much coal-
fueled capacity as retired in the 22 years from 1990 through April 
2012.[Footnote 16] Based on our statistical analysis of these plans, 
power companies are more likely to plan to retire units that are 
older, smaller, and more polluting. (Appendix I provides further 
information on our statistical analysis, which included examining 
several other characteristics that may affect plans to retire units 
such as (1) whether power companies are traditionally regulated or 
operate in restructured markets and (2) a unit's cost of generating 
electricity relative to regional prices.) 

* Older. Power companies' plans indicate they are more likely to 
retire older coal-fueled electricity generating units than newer 
units. Today's fleet of operating coal-fueled units was built from 
1943 through 2012, with the bulk of the capacity built in the 1970s 
and early 1980s. As shown in figure 4, units that power companies plan 
to retire are generally older, on average 54 years old compared with 
units with no retirement plans that average 39 years old. Some 
stakeholders we interviewed said that power companies are more likely 
to retire older units because these units may be reaching the end of 
their useful lives, can be less efficient at converting coal to 
electricity, and can be more expensive than newer units to retrofit, 
maintain, and operate. 

Figure 4: Capacity of Coal-Fueled Units by Year of First Commercial 
Operation and Planned Retirements: 

[Refer to PDF for image: vertical bar graph] 

Values are in thousand MW. 

Year: 1943; 
No retirement planned: 0.05; 
Planned for retirement: 0.05. 

Year: 1944; 
No retirement planned: 0; 
Planned for retirement: 0.09. 

Year: 1947; 
No retirement planned: 0; 
Planned for retirement: 0.03. 

Year: 1948; 
No retirement planned: 0; 
Planned for retirement: 0.06. 

Year: 1949; 
No retirement planned: 0.18; 
Planned for retirement: 0.56. 

Year: 1950; 
No retirement planned: 0.56; 
Planned for retirement: 0.46. 

Year: 1951; 
No retirement planned: 0.30; 
Planned for retirement: 1.20. 

Year: 1952; 
No retirement planned: 0.61; 
Planned for retirement: 1.48. 

Year: 1953; 
No retirement planned: 1.83; 
Planned for retirement: 1.80. 

Year: 1954; 
No retirement planned: 3.08; 
Planned for retirement: 1.81. 

Year: 1955; 
No retirement planned: 5.11; 
Planned for retirement: 0.82. 

Year: 1956; 
No retirement planned: 0.98; 
Planned for retirement: 0.74. 

Year: 1957; 
No retirement planned: 1.89; 
Planned for retirement: 1.29. 

Year: 1958; 
No retirement planned: 3.54; 
Planned for retirement: 3.12. 

Year: 1959; 
No retirement planned: 3.96; 
Planned for retirement: 2.46. 

Year: 1960; 
No retirement planned: 3.35; 
Planned for retirement: 0.77. 

Year: 1961; 
No retirement planned: 4.00; 
Planned for retirement: 0.55. 

Year: 1962; 
No retirement planned: 1.55; 
Planned for retirement: 2.23. 

Year: 1963; 
No retirement planned: 3.11; 
Planned for retirement: 0.74. 

Year: 1964; 
No retirement planned: 3.60; 
Planned for retirement: 0.54. 

Year: 1965; 
No retirement planned: 5.02; 
Planned for retirement: 0.27. 

Year: 1966; 
No retirement planned: 3.39; 
Planned for retirement: 0.71. 

Year: 1967; 
No retirement planned: 6.92; 
Planned for retirement: 0.52. 

Year: 1968; 
No retirement planned: 8.26; 
Planned for retirement: 0.83. 

Year: 1969; 
No retirement planned: 9.45; 
Planned for retirement: 1.95. 

Year: 1970; 
No retirement planned: 10.36; 
Planned for retirement: 0.81. 

Year: 1971; 
No retirement planned: 10.76; 
Planned for retirement: 0.03. 

Year: 1972; 
No retirement planned: 9.99; 
Planned for retirement: 1.64. 

Year: 1973; 
No retirement planned: 15.32; 
Planned for retirement: 0. 

Year: 1974; 
No retirement planned: 10.51; 
Planned for retirement: 0.57. 

Year: 1975; 
No retirement planned: 10.11; 
Planned for retirement: 0.57. 

Year: 1976; 
No retirement planned: 8.00; 
Planned for retirement: 0. 

Year: 1977; 
No retirement planned: 11.11; 
Planned for retirement: 0.44. 

Year: 1978; 
No retirement planned: 11.45; 
Planned for retirement: 0.59. 

Year: 1979; 
No retirement planned: 9.86; 
Planned for retirement: 0.08. 

Year: 1980; 
No retirement planned: 14.03; 
Planned for retirement: 1.11. 

Year: 1981; 
No retirement planned: 9.70; 
Planned for retirement: 0. 

Year: 1982; 
No retirement planned: 11.60; 
Planned for retirement: 0. 

Year: 1983; 
No retirement planned: 6.31; 
Planned for retirement: 0. 

Year: 1984; 
No retirement planned: 10.44; 
Planned for retirement: 0. 

Year: 1985; 
No retirement planned: 6.80; 
Planned for retirement: 0. 

Year: 1986; 
No retirement planned: 6.01; 
Planned for retirement: 0. 

Year: 1987; 
No retirement planned: 4.40; 
Planned for retirement: 0. 

Year: 1988; 
No retirement planned: 1.67; 
Planned for retirement: 0. 

Year: 1989; 
No retirement planned: 3.13; 
Planned for retirement: 0. 

Year: 1990; 
No retirement planned: 1.98; 
Planned for retirement: 0. 

Year: 1991; 
No retirement planned: 3.08; 
Planned for retirement: 0. 

Year: 1992; 
No retirement planned: 1.38; 
Planned for retirement: 0. 

Year: 1993; 
No retirement planned: 0.65; 
Planned for retirement: 0. 

Year: 1994; 
No retirement planned: 0.42; 
Planned for retirement: 0. 

Year: 1995; 
No retirement planned: 2.07; 
Planned for retirement: 0. 

Year: 1996; 
No retirement planned: 1.76; 
Planned for retirement: 0. 

Year: 1997; 
No retirement planned: 0.08; 
Planned for retirement: 0. 

Year: 1999; 
No retirement planned: 0.27; 
Planned for retirement: 0. 

Year: 2000; 
No retirement planned: 0.16; 
Planned for retirement: 0. 

Year: 2002; 
No retirement planned: 0.44; 
Planned for retirement: 0. 

Year: 2003; 
No retirement planned: 0.09; 
Planned for retirement: 0. 

Year: 2004; 
No retirement planned: 0.63; 
Planned for retirement: 0. 

Year: 2005; 
No retirement planned: 0.29; 
Planned for retirement: 0. 

Year: 2006; 
No retirement planned: 0.58; 
Planned for retirement: 0. 

Year: 2007; 
No retirement planned: 1.47; 
Planned for retirement: 0. 

Year: 2008; 
No retirement planned: 1.45; 
Planned for retirement: 0. 

Year: 2009; 
No retirement planned: 3.20; 
Planned for retirement: 0. 

Year: 2010; 
No retirement planned: 6.01; 
Planned for retirement: 0. 

Year: 2011; 
No retirement planned: 1.88; 
Planned for retirement: 0. 

Year: 2012; 
No retirement planned: 2.09; 
Planned for retirement: 0. 

Source: GAO analysis of Ventyx data. 

Note: Data are for coal-fueled electricity generating units greater 
than 25 MW net summer capacity, and planned retirements represent 
plans through 2020. Net summer capacity is a unit's capacity to 
generate electricity during the summer when electricity demand for 
many electricity systems and losses in efficiency are generally the 
highest. Net capacity excludes output used internally for plant 
operations. 

[End of figure] 

* Smaller. The smaller a unit is, the more likely a power company is 
to be planning to retire it. (See figure 5.) Size can be important 
when assessing the economics of additional investments needed to 
continue to operate coal-fueled units, as smaller units can be more 
expensive to retrofit, maintain, and operate on a per-MW basis. For 
example, some power companies may choose to install flue gas 
desulfurization units--known as scrubbers--to control SO2 and other 
air emissions.[Footnote 17] According to an EPA report, a typical 100 
MW coal-fueled unit could incur capital costs 66 to 74 percent higher 
per MW to install a scrubber than a 700 MW unit.[Footnote 18] In 
addition, smaller generating units are generally less fuel-efficient 
than larger units. Units that are planned for retirement average 175 
MW of capacity compared with units that are not planned for retirement 
that average 351 MW of capacity. Figure 5 shows the number of coal-
fueled units by capacity in MW. 

Figure 5: Number of Coal-Fueled Electricity Generating Units by 
Capacity Category: 

[Refer to PDF for image: stacked vertical bar graph] 

Number of units: 

Net summer capacity (MW): 25-100; 
No retirement planned: 147; 
Retirement planned: 49. 

Net summer capacity (MW): 100-200; 
No retirement planned: 173; 
Retirement planned: 77. 

Net summer capacity (MW): 200-300; 
No retirement planned: 90; 
Retirement planned: 28. 

Net summer capacity (MW): 300-400; 
No retirement planned: 68; 
Retirement planned: 7. 

Net summer capacity (MW): 400-500; 
No retirement planned: 60; 
Retirement planned: 4. 

Net summer capacity (MW): 500-600; 
No retirement planned: 85; 
Retirement planned: 6. 

Net summer capacity (MW): 600-700; 
No retirement planned: 76; 
Retirement planned: 2. 

Net summer capacity (MW): 700-800; 
No retirement planned: 38; 
Retirement planned: 1. 

Net summer capacity (MW): 800-900; 
No retirement planned: 34. 

Net summer capacity (MW): more than 900; 
No retirement planned: 14. 

Source: GAO analysis of Ventyx data. 

Note: Data are for coal-fueled electricity generating units greater 
than 25 MW net summer capacity, and planned retirements represent 
plans through 2020. Net summer capacity is a unit's capacity to 
generate electricity during the summer when electricity demand for 
many electricity systems and losses in efficiency are generally the 
highest. Net capacity excludes output used internally for plant 
operations. 

[End of figure] 

* More polluting. Power companies' plans indicate they are more likely 
to retire units that emit SO2 and NOx at higher rates. Units in which 
pollution control equipment has been installed may require relatively 
minimal additional investments to meet new environmental regulatory 
requirements. For example, for units without controls to limit mercury 
emissions, power companies may have to install scrubbers or other 
controls, whereas units with such controls may already be able to meet 
new emissions limits. Fewer of the units that are planned for 
retirement have pollution control equipment and, therefore, units 
planned for retirement emit air pollutants such as SO2 and NOx at 
higher rates than the fleet overall. For example, 12 percent of the 
units planned for retirement have equipment installed to reduce SO2 
emissions, while almost 60 percent of units with no retirement plans 
have such equipment. As a result, units planned for retirement emitted 
an average of over twice as much SO2 per unit of energy used in 2011 
as units that are not planned for retirement--1.5 pounds of SO2 for 
units planned for retirement compared with 0.6 pounds of SO2 per 
million British thermal units (Btu) of energy used for units not 
planned for retirement (see figure 6).[Footnote 19] Similarly, units 
planned for retirement emitted on average about 60 percent more NOx 
and 1 percent more CO2 than units not planned for retirement. 

Figure 6: Number of Coal-Fueled Electricity Generating Units by 2011 
SO2 Emissions Rate: 

[Refer to PDF for image: stacked vertical bar graph] 

Number of units: 

SO2 emissions rate (lbs/million Btu): 0-1; 
No retirement planned: 663; 
Retirement planned: 58. 

SO2 emissions rate (lbs/million Btu): 1-2; 
No retirement planned: 67; 
Retirement planned: 71. 

SO2 emissions rate (lbs/million Btu): 2-3; 
No retirement planned: 43; 
Retirement planned: 31. 

SO2 emissions rate (lbs/million Btu): 3-4; 
No retirement planned: 5; 
Retirement planned: 7. 

SO2 emissions rate (lbs/million Btu): more than 4; 
No retirement planned: 7; 
Retirement planned: 7. 

Source: GAO analysis of Ventyx data. 

Note: A British thermal unit (Btu) is a measure of energy and equals 
the heat required to raise the temperature of 1 pound of water by 1 
degree Fahrenheit. Data are for coal-fueled electricity generating 
units greater than 25 MW net summer capacity, and planned retirements 
represent plans through 2020. Net summer capacity is a 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 excludes output used internally for plant 
operations. 

[End of figure] 

Based on our statistical analysis of the characteristics associated 
with current retirement plans, we examined units owned by companies 
that have not announced any retirements to estimate the number of 
additional units and associated generating capacity that power 
companies may consider retiring.[Footnote 20] Our analysis is subject 
to some uncertainty, and we therefore identified a range of units that 
power companies may consider retiring.[Footnote 21] In addition to the 
174 coal-fueled units with 30,447 MW of capacity (10 percent of total 
coal-fueled capacity in 2011) that are currently planned for 
retirement through 2020, our analysis predicts an additional 90 to138 
coal-fueled units with 15,700 MW to 25,200 MW of capacity (5 to 8 
percent of total) that companies may consider retiring. The capacity 
of units already planned for retirement (10 percent of total 
capacity), together with this additional capacity (5 to 8 percent of 
total capacity), suggests that 15 to 18 percent of total coal-fueled 
generating capacity could retire--an amount generally consistent with 
other forecasts we reviewed. 

Many Units May Be Retrofitted with Pollution Control Equipment: 

As we reported in July 2012, power companies may retrofit many coal-
fueled electricity generating units with new or upgraded pollution 
control equipment in response to new environmental regulatory 
requirements.[Footnote 22] Though the requirements and deadlines these 
regulations may establish for generating units are somewhat uncertain 
at this time, EPA's analyses and two other studies we reviewed in our 
prior report suggest that one-third to three-quarters of all coal-
fueled capacity could be retrofitted or upgraded with some combination 
of pollution control equipment, including scrubbers and other 
technologies to reduce SO2, mercury, and other emissions. Once 
retrofitted with this pollution control equipment, the coal-fueled 
fleet would be capable of generating electricity and emitting much 
lower levels of pollution. For example, EPA projects that mercury 
emissions from coal-fueled electricity generating units will decrease 
by 75 percent as a result of its new regulatory requirements. 
Nevertheless, even the cleanest running coal-fueled unit may still be 
more polluting than generating units that use other fuel sources. For 
example, the 10 least-emitting coal-fueled units emitted over 10 times 
as much SO2 per unit of energy input than the average combined cycle 
natural gas unit in 2011--an average of 0.007 pounds of SO2 per 
million Btu compared with an average of 0.0006 for combined cycle 
units.[Footnote 23] Electricity generating units that rely on solar 
and wind sources produce no such emissions. 

Some New Generating Units May Be Built and Would Be Larger, Cleaner, 
and More Efficient Than the Fleet Overall: 

Available information suggests that industry intends to build some new 
coal-fueled electricity generating units. According to Ventyx data, 
power companies have plans to build 42 new coal-fueled electricity 
generating units with 21,634 MW of capacity in various stages of 
planning or development (see figure 7). However, as we have previously 
reported, developers generally have more planned projects than they 
complete.[Footnote 24] 

Figure 7: Capacity of Planned Coal-Fueled Electricity Generating Units 
by Status, as of July 26, 2012: 

[Refer to PDF for image: stacked vertical bar graph] 

Status: Testing (operating under test conditions); 
Capacity: 1.4 thousand MW. 

Status: Under construction (unit under construction); 
Capacity: 3.5 thousand MW. 

Status: Site preparation (site is being prepared for construction; 
Capacity: 0.6 thousand MW. 

Status: Permitted (two or more permits have been approved or contracts 
received); 
Capacity: 8.8 thousand MW. 

Status: Application pending (permits and regulatory approvals pending; 
Capacity: 1.8 thousand MW. 

Status: Proposed (new generating unit planned); 
Capacity: 5.6 thousand MW. 

Source: GAO analysis of Ventyx data. 

Note: Data refer to net summer capacity--the generating unit's 
capacity to generate electricity during the summer when electricity 
demand for many electricity systems and losses in efficiency are 
generally the highest. Net capacity excludes output used internally 
for plant operations. 

[End of figure] 

The total capacity of coal-fueled electricity generating units in the 
United States may decline in the future as less capacity is expected 
to be built than is expected to retire. As discussed, 49,000 to 76,476 
MW of coal-fueled capacity is projected to retire by 2035 according to 
EIA and IHS Global Insight, respectively, and they project that 11,000 
MW and 22,134 MW of new coal-fueled capacity will be added by 2035, 
respectively. EIA officials told us that new coal-fueled capacity in 
their projections is primarily expected in the next few years and 
represents units that are already planned or under construction. As 
less capacity is expected to be built than is expected to retire, 
total coal-fueled capacity is expected to decline in the future, as 
shown in figure 8. Coal's share of total electricity generating 
capacity was about 30 percent in 2011. In EIA's reference scenario, 
coal's share of capacity declines to 25 percent in 2035 as retiring 
coal-fueled units are not fully replaced, and as 176,100 MW of other 
generating capacity is added in the future. 

Figure 8: Actual 2011 and Projected 2035 Coal-Fueled Electricity 
Generating Capacity: 

[Refer to PDF for image: vertical bar graph] 

Year: 2011; 
Actual: 317 thousand MW 

Year: 2035; 
EIA reference scenario: 275 thousand MW; 
IHS Global Insight: 262 thousand MW. 

Source: GAO analysis of EIA reference scenario and IHS Global Insight 
data. 

[End of figure] 

Any coal-fueled units that are built in the future are likely to be 
larger, less polluting, and more fuel-efficient than the average of 
the coal-fueled fleet overall. Units that power companies are 
currently planning to build average 515 MW of net summer capacity, and 
the operating fleet averages 319 MW.[Footnote 25] Additionally, new 
units must install technologies to control emissions, and so are 
likely to emit lower levels of pollutants and thus be cleaner than the 
fleet overall. For example, generating units built after August 7, 
1977, have had to obtain preconstruction permits that establish air 
emissions limits and require the use of certain emissions control 
technologies such as scrubbers to reduce emissions of SO2.[Footnote 
26] In addition, some stakeholders we interviewed said that new coal-
fueled units were likely to incorporate designs that are able to 
convert fuel to electricity more efficiently. 

Coal Likely to Remain a Key Fuel Source, but Future Use May Be 
Affected by Fuel Prices, Environmental Regulations, and Other Factors: 

Coal is likely to continue to be a key fuel source for electricity 
generation in the United States, but its share as a source of 
electricity is expected to decline, and the future use of coal to 
generate electricity in the United States may be affected by several 
key factors that include the price of natural gas and other competing 
fuels, environmental regulations, and the demand for electricity, 
among others. In addition, several stakeholders we interviewed said 
that coal may increasingly be exported for use in other nations, 
though the extent of future exports is uncertain. 

Coal Likely to Continue to Be a Key Source of Electricity in the 
Future, though Its Share Is Generally Expected to Decline in the 
United States: 

According to stakeholders we interviewed and projections by EIA, IEA, 
and IHS Global Insight, coal is likely to continue to be a key fuel 
source for U.S. electricity generation, but its share as a source of 
electricity is generally expected to decline in the future. Some 
stakeholders told us that, in the future, electricity generation from 
coal is likely to be displaced by generation from other fuel sources, 
particularly natural gas, but they still expect coal's contribution to 
electricity generation to be significant. Furthermore, in its 
reference scenario, EIA estimates that coal will represent 38 percent 
of U.S. electricity generation in 2035 under current policies--down 
from 42 percent in 2011.[Footnote 27] As shown in figure 9, the total 
amount of electricity generated using coal is expected to remain 
relatively constant over this same period under EIA's reference 
scenario, growing by 0.1 percent annually. However, the amount of 
electricity generated using some other fuel sources, for example, 
natural gas and renewables, will increase at higher annual rates--1.4 
percent and 2.3 percent respectively--diminishing coal's total share 
of electricity generation. 

Figure 9: EIA's Reference Scenario Projections of Electricity 
Generation by Fuel: 

[Refer to PDF for image: stacked vertical bar graph] 

2009: 
Coal: 1.8 billion MWh; 
Petroleum: 0.04 billion MWh; 
Natural Gas: 0.9 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.4 billion MWh; 
Other: 0.02 billion MWh. 

2010: 
Coal: 1.9 billion MWh; 
Petroleum: 0.04 billion MWh; 
Natural Gas: 1.0 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.4 billion MWh; 
Other: 0.02 billion MWh. 

2011: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.0 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.5 billion MWh; 
Other: 0.02 billion MWh. 

2012: 
Coal: 1.7 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.5 billion MWh; 
Other: 0.02 billion MWh. 

2013: 
Coal: 1.7 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.0 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.5 billion MWh; 
Other: 0.02 billion MWh. 

2014: 
Coal: 1.6 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.5 billion MWh; 
Other: 0.02 billion MWh. 

2015: 
Coal: 1.6 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2016:
Coal: 1.6 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.8 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2017: 
Coal: 1.6 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2018: 
Coal: 1.6 billion MWh;  
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2019:
Coal: 1.6 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2020: 
Coal: 1.7 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh;  
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2021: 
Coal: 1.7 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2022: 
Coal: 1.7 billion MWh;  
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2023: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2024: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.6 billion MWh; 
Other: 0.02 billion MWh. 

2025: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.1 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2026: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.2 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2027: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.2 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2028: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.2 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2029: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.2 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2030: 
Coal: 1.8 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.3 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2031: 
Coal: 1.9 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.3 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2032: 
Coal: 1.9 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.3 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2033: 
Coal: 1.9 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.3 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2034: 
Coal: 1.9 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.4 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.7 billion MWh; 
Other: 0.02 billion MWh. 

2035: 
Coal: 1.9 billion MWh; 
Petroleum: 0.03 billion MWh; 
Natural Gas: 1.4 billion MWh; 
Nuclear Power: 0.9 billion MWh; 
Renewable Sources: 0.8 billion MWh; 
Other: 0.02 billion MWh. 

Source: EIA. 

Note: Data from 2009 and 2010 represent historical data. Data from 
2011 and after represent EIA estimates. Renewable sources include 
conventional hydroelectric, geothermal, wood, wood waste, certain 
municipal wastes, landfill gas, other biomass, solar, and wind power. 
Other includes pumped storage, certain municipal wastes, refinery gas, 
still gas, batteries, chemicals, hydrogen, pitch, purchased steam, 
sulfur, and miscellaneous technologies. 

[End of figure] 

IEA, in its current policies scenario, which considers policies 
enacted by mid-2011, projects that coal's share of electricity 
generation will increase slightly to 43 percent in 2035. IHS Global 
Insight, which assumes some changes in current U.S. policies in its 
analysis, projects that coal's share of electricity generation will 
decline to 26 percent in 2035. 

Power companies are expected to retire a significant number of coal-
fueled generating units in the future, but these retirements may have 
more of an impact on coal-fueled capacity than on electricity 
generation from coal. As discussed, our statistical analysis suggests 
that 15 to 18 percent of total coal-fueled generating capacity could 
retire. Units that may retire did not run as intensively as coal-
fueled units overall, and we estimate they may account for 13 to 16 
percent of the annual average electricity generation from coal. 
[Footnote 28] (See appendix I for additional information on our 
statistical analysis.) 

The changes in coal use may also result in shifts between major coal-
producing areas in the United States. As shown in figure 10, EIA 
identifies three broad coal-producing regions in the United States: 
Appalachia, the Interior region spanning coal-producing areas in 
central states to Texas, and the Western region covering coal-
producing areas in western states and Alaska. In EIA's reference 
scenario, coal production from Appalachia declines, and production 
from the Western and Interior regions increases through 2035.[Footnote 
29] According to EIA, in 2010, 31 percent of coal was produced in 
Appalachia, 14 percent was produced in the Interior region of the 
United States, and 55 percent was produced in the West. As shown in 
figure 10, EIA's reference scenario projects that these production 
figures will change by 2035, with 24 percent of coal produced in 
Appalachia, 16 percent produced in the Interior region, and 60 percent 
produced in the Western region. 

Figure 10: Actual 2010 and EIA's Reference Scenario Projected 2035 
Coal Production by Region: 

[Refer to PDF for image: illustrated U.S. map and associated stacked 
vertical bar graph] 

Year: 2010; 
Appalachian: 336 million tons; 
Interior: 156 million tons; 
Western: 592 million tons. 

Year: 2035; 
Appalachian: 291 million tons; 
Interior: 198 million tons; 
Western: 722 million tons. 

Source: GAO analysis of EIA data; copyright: Corl Corp., all rights 
reserved (map). 

[End of figure] 

Within Appalachia, EIA expects declines to come from the central 
region, which includes southern West Virginia, Virginia, eastern 
Kentucky, and northern Tennessee. This expected shift in coal 
production from the eastern United States to the West represents an 
industry trend ongoing since the early 1990s that is influenced by 
each region's unique set of complex geological, mining, and 
transportation characteristics. For example, some stakeholders told us 
that demand for western coal has increased primarily because it is low 
in sulfur content, and the region's coal reserves can be mined 
relatively inexpensively compared with Appalachian and Interior coal 
reserves, which are often more deeply underground and costlier to 
access. Available information suggests that these benefits have made 
western coal economically competitive with coal from the Appalachian 
and Interior regions, despite western coal's lower heating value and 
higher cost to transport to some coal-fueled generating units. 

Future Fuel Prices, Environmental Regulations, and Other Factors May 
Affect the Use of Coal in the United States: 

According to available information, the future use of coal to generate 
electricity in the United States may be determined by several key 
factors. 

Prices for Natural Gas and Other Competing Fuels: 

Available information suggests that the price of coal compared to the 
prices of other fuel sources could influence how economically 
attractive it is to use coal to generate electricity. This can affect 
how often existing coal-fueled generating units are used, how many 
units are retired, and how many new units are built. In general, the 
decision about whether to operate a given generating unit is based on 
the costs of operating that unit. Operating costs are driven, in part, 
by the cost of fuel sources and how efficiently fuels are converted 
into electricity. In general, new natural gas-fueled generating units 
are able to convert fuel into electricity more efficiently than 
existing coal-fueled generating units, meaning they can convert a unit 
of fuel energy into more electricity than less-efficient coal-fueled 
units. Some natural gas-fueled units constructed in the last decade 
can require less than 7,000,000 Btus of natural gas to generate one 
MWh of electricity. In contrast, existing coal-fueled generating units 
require around 10,000,000 Btus of coal to generate one MWh of 
electricity, and 187 coal-fueled units require over 12,000,000 Btus 
per MWh. Newer designs of coal-fueled units exist that can operate at 
higher efficiencies, but few have been built in the United States. 

Generally, generating units with the lowest costs operate more often 
than units with higher costs. If the price of natural gas falls 
relative to coal in a particular region, depending on each unit's 
efficiency, it may result in the operating costs of some natural gas 
units dropping below the operating costs of some coal units and, thus, 
natural gas units being operated more often--and coal units less 
often--than before. We previously reported that, in some areas of the 
country, it has become less economically attractive to use coal to 
generate electricity, as the regional prices of coal have increased, 
the prices of natural gas have fallen, and the availability of natural 
gas has increased.[Footnote 30] Multiple stakeholders told us that if 
natural gas prices remain low relative to coal prices, this trend 
could continue. As shown in figure 11, prices of coal and natural gas 
have varied historically, and EIA and IHS Global Insight project a 
range of potential future prices in their forecast scenarios. 

Figure 11: Actual and Projected Coal and Natural Gas Prices: 

[Refer to PDF for image: multiple line graph] 

2012 year dollars per million Btu: 

Year: 1990; 
Coal: $2.32; 
Natural Gas: $3.70. 

Year: 1991; 
Coal: $2.24; 
Natural Gas: $3.32. 

Year: 1992; 
Coal: $2.12; 
Natural Gas: $3.51. 

Year: 1993; 
Coal: $2.05; 
Natural Gas: $3.77. 

Year: 1994; 
Coal: $1.96; 
Natural Gas: $3.22. 

Year: 1995; 
Coal: $1.87; 
Natural Gas: $2.80. 

Year: 1996; 
Coal: $1.79; 
Natural Gas: $3.66. 

Year: 1997; 
Coal: $1.73; 
Natural Gas: $3.76. 

Year: 1998; 
Coal: $1.69; 
Natural Gas: $3.21. 

Year: 1999; 
Coal: $1.62; 
Natural Gas: $3.42. 

Year: 2000; 
Coal: $1.56; 
Natural Gas: $5.59. 

Year: 2001; 
Coal: $1.56; 
Natural Gas: $5.71. 

Year: 2002; 
Coal: $1.57; 
Natural Gas: $4.46. 

Year: 2003; 
Coal: $1.57; 
Natural Gas: $6.61. 

Year: 2004; 
Coal: $1.62; 
Natural Gas: $7.11. 

Year: 2005; 
Coal: $1.78; 
Natural Gas: $9.47. 

Year: 2006; 
Coal: $1.89; 
Natural Gas: $7.75. 

Year: 2007; 
Coal: $1.92; 
Natural Gas: $7.72. 

Year: 2008; 
Coal: $2.20; 
Natural Gas: $9.58. 

Year: 2009; 
Coal: $2.33; 
Natural Gas: $5.00. 

Year: 2010; 
Coal: $2.36; 
Natural Gas: $5.29. 

Year: 2011; 
Coal: $2.44; 
Natural Gas: $4.79. 

Year: 2012[A]; 
Coal: $2.41; 
Natural Gas: $3.10. 

2035 Projected Prices: 

IHS Global Insight: 
Coal: $2.43; 
Natural Gas: $5.70. 

EIA Reference: 
Coal: $2.91; 
Natural Gas: $7.50. 

EIA high coal price: $4.98; 
EIA low coal price: $1.84; 
EIA high natural gas price: $8.23; 
EIA low natural gas price: $4.68. 

Source: GAO analysis of EIA and IHS Global Insight data. 

Note: Shading is not indicative of projected prices between 2012 and 
2035. As described above, both fuel prices and efficiency will affect 
a generating unit's operating costs and, thus, how often one unit 
operates compared with another. Many newer natural gas-fueled units 
are more efficient than coal-fueled units, and when the price of 
natural gas drops to a certain level relative to coal prices, it 
becomes less costly to operate these efficient natural gas units than 
coal units. Data for the high price scenarios were obtained from EIA's 
"Low Estimated Ultimate Recovery" and "High Coal Cost" scenarios. 
These scenarios had the highest prices for natural gas and coal 
delivered to the electricity sector after the two greenhouse gas 
scenarios discussed later in this report. Data for the low price 
scenarios were obtained from EIA's "High Total Recoverable Resources" 
and "Low Coal Cost" scenarios. Data converted to 2012 year dollars 
using the gross domestic product deflator based on the calendar year. 

[A] Average through June 2012. 

[End of figure] 

EIA's forecast suggests that future fuel prices may influence the 
extent to which coal is used to generate electricity. As shown in 
Table 1, four EIA scenarios project that the share of total 
electricity generated using coal could vary from 30 to 42 percent in 
2035 based on fuel prices. See appendix II for further information 
about these scenarios. 

Table 1: Results of EIA Alternate Fuel Price Scenarios: 

Scenario: Actual, 2010; 
Electricity generated using coal (million MWh): 1,851; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): Not applicable; 
Share of total electricity generated using coal: 45. 

Scenario: Actual, 2011; 
Electricity generated using coal (million MWh): 1,734; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): Not applicable; 
Share of total electricity generated using coal: 42. 

Scenario: Reference Scenario, 2035; 
Electricity generated using coal (million MWh): 1,897; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): 0.1%; 
Share of total electricity generated using coal: 38. 

Scenario: Scenario with High Coal Prices, 2035; 
Electricity generated using coal (million MWh): 1,577; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): -0.6%; 
Share of total electricity generated using coal: 32. 

Scenario: Scenario with Low Coal Prices, 2035; 
Electricity generated using coal (million MWh): 2,107; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): 0.5%; 
Share of total electricity generated using coal: 42. 

Scenario: Scenario with High Natural Gas Prices, 2035; 
Electricity generated using coal (million MWh): 1,977; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): 0.3%; 
Share of total electricity generated using coal: 40. 

Scenario: Scenario with Low Natural Gas Prices, 2035; 
Electricity generated using coal (million MWh): 1,542; 
Average annual percent change in electricity generated using coal, 
2010-2035 (percentage): -0.7%; 
Share of total electricity generated using coal: 30. 

Source: EIA, 2012 Annual Energy Outlook. Actual 2011 data are from 
EIA's August 2012 Electric Power Monthly. 

Note: Data for the high price scenarios were obtained from EIA's "Low 
Estimated Ultimate Recovery" and "High Coal Cost" scenarios. These 
scenarios had the highest prices for natural gas and coal delivered to 
the electricity sector after the two greenhouse gas scenarios 
discussed later in this report. Data for the low price scenarios were 
obtained from EIA's "High Total Recoverable Resources" and "Low Coal 
Cost" scenarios. 

[End of table] 

Current and Future Environmental Regulations and Renewable Energy 
Policies: 

Available information indicates that existing and potential future 
regulations may make it more expensive to generate electricity using 
coal, thus affecting coal's future use. Some stakeholders we spoke 
with indicated that current and proposed regulations addressing air 
pollution, water pollution, and wastes from using coal could adversely 
affect coal in the future by making it more expensive to generate 
electricity using coal.[Footnote 31] Some stakeholders also said that 
coal would be adversely affected by efforts to reduce greenhouse gas 
emissions from the electricity industry, such as by a regulation EPA 
proposed in 2012--new source performance standards for greenhouse gas 
emissions, which would establish limits on the amount of CO2 that new 
generating units can emit--as well as the potential for additional 
federal efforts to regulate greenhouse gases.[Footnote 32] Available 
information also indicates that the extent to which these regulations 
adversely affect coal will depend, in part, on the future economics 
and development of technologies to address CO2 emissions from coal-
fueled units, such as technologies to capture and store CO2. The 
development of effective and commercially viable CO2 controls for coal-
fueled electricity generating units has received significant 
attention, but some of these technologies are still in the research 
and development phase, and most are not yet commercially viable. 
[Footnote 33] 

Though it is unclear whether there will be additional future efforts 
to reduce CO2 emissions, EIA assessed two scenarios examining 
hypothetical future policies. One scenario has a hypothetical price on 
CO2 emissions starting at $15 per ton in 2013 that increases 5 percent 
per year and that would reduce CO2 emissions from the electric power 
sector by 46 percent below 2010 levels in 2035. Another scenario has 
an initial price on CO2 emissions of $25 per ton that increases 5 
percent per year and would reduce CO2 emissions from the electric 
power sector by 76 percent below 2010 levels in 2035. EIA stated that 
these scenarios are consistent with previously proposed legislation. 
EIA projected that, under these two scenarios, coal's share of total 
electricity generation could fall to 16 and 4 percent in 2035, 
respectively. IEA also developed scenarios that took potential 
additional efforts to address climate change into account--one 
scenario that considers the United States' international commitments, 
even if nonbinding, and a second scenario that considers an approach 
to energy use in the United States consistent with more significant 
future steps to address climate change. Under these scenarios, IEA 
estimates that 35 and 17 percent of U.S. electricity would be 
generated by coal, respectively.[Footnote 34] 

In addition, many states have policies in place requiring power 
companies to increasingly rely on renewable sources for electricity, 
and similar proposals have been introduced at the federal level. We 
have previously reported that 30 states have laws or regulations 
requiring power companies to increasingly rely on renewable sources 
for electricity.[Footnote 35] At the federal level, there have been 
several efforts to establish a national renewable portfolio standard. 
For example, a Senate bill introduced in March 2012 would require 
power companies to obtain a certain amount of the electricity they 
sell from clean energy sources with zero or low carbon generation, 
such as renewable energy, natural gas, and nuclear power. An EIA 
analysis of this bill suggests that such a policy could increase 
demand for renewables and other sources favored by these rules and 
diminish demand for electricity from coal.[Footnote 36] 

Demand for Electricity: 

Available information suggests that future electricity demand levels 
may affect the use of coal to generate electricity. In general, if 
more electricity is needed in the future, it becomes more likely that 
existing generating units that are not already running at capacity--
including coal units--will be operated more often. Lower demand makes 
it more likely that the opposite will happen. Demand levels also 
influence decisions about whether to build new generating units, 
including coal-fueled units, with high demand scenarios increasing the 
likelihood that new units will be operated frequently enough to 
recover the capital costs associated with their construction. 
According to EIA, electricity demand is affected by factors including 
population growth and economic growth. In general, electricity use 
increases as the economy grows, but improvements in energy efficiency 
can offset some or all of the increases in electricity use due to 
economic growth. 

Electricity demand varies across EIA's scenarios. In its high economic 
growth scenario, in which future electricity demand is the highest, 
total demand for electricity generated using coal grows at an annual 
rate of 0.3 percent from 2010 to 2035 to 2,004 million MWh in 2035, 
higher than the 1,897 million MWh estimate from EIA's reference 
scenario. However, in this scenario, EIA does not predict a 
significant change in coal's share of total electricity generation--37 
percent compared with 38 percent in the reference scenario. EIA's 
scenario that assumes high use of energy efficient technologies in the 
residential and commercial sectors estimates the lowest future demand 
for electricity. In this scenario, electricity generated from coal 
declines at an annual rate of 1.1 percent to 1,414 million MWh in 
2035, and electricity generated from coal constitutes 34 percent of 
total electricity generation that year. 

Other Factors: 

A variety of other factors may also affect the future of coal in the 
United States. For example, some stakeholders told us that local 
opposition to coal by environmental activists and other concerned 
citizens has and will continue to adversely impact its future use. 
According to some other stakeholders, coal's future will also be 
influenced by the extent to which technologies to reduce coal's 
environmental impact become commercially available and economic. For 
example, technology to capture and store carbon underground has the 
potential to address the adverse greenhouse gas impacts of electricity 
generation using coal, which could increase demand for coal. 

Extent of Future Coal Exports Is Uncertain: 

Several stakeholders we interviewed said that U.S. coal may 
increasingly be exported for use in the electricity sector and for 
other purposes, but the extent of future U.S. coal exports is 
uncertain. According to IEA, world demand for coal grew rapidly from 
2000 to 2010, and coal accounted for nearly half the increase in 
global energy use over that period. Additionally, according to IEA, 
world coal demand is strongly correlated with global economic activity 
and will also be affected by world energy and environmental 
regulations and the development and use of technologies to reduce 
coal's environmental impact. 

Available information suggests that the future level of U.S. coal 
exports will also depend on how competitive U.S. coal prices are 
internationally and the extent to which the quality of coal available 
from the United States is in demand. For example, metallurgical coal--
coal used for such activities as steel production--has historically 
constituted a significant share of U.S. coal exports. Factors 
affecting the ability of other coal-exporting countries to 
economically and reliably supply coal to international customers 
include local freight rates, limits on the amount of exports, and 
extreme weather events--all of which can influence the relative price 
of U.S. coal and, thus, the amount of U.S. coal exported. 

According to EIA's reference scenario, coal exports are estimated to 
grow 1.8 percent annually from 2010 to 2035, reaching 129 million tons 
of coal (11 percent of total U.S. production) in 2035. On the other 
hand, IHS Global Insight projects that exports will fall 1 percent 
annually from 2010 to 2035, with 62.8 million tons of coal being 
exported in 2035 (7 percent of total U.S. production). 

Agency Comments and Our Evaluation: 

We met with EIA officials to discuss an early draft of this report and 
incorporated technical suggestions where appropriate. We also provided 
a draft of this report to EIA and EPA for formal comment. EIA and EPA 
did not provide written comments for inclusion in this report. EPA's 
Office of Air and Radiation did provide technical comments and stated 
that the report contained a very good description of many of the 
changes going on in coal and electricity markets that are affecting 
the use of coal to generate electricity. In its technical comments, 
EPA suggested that the draft's emphasis on environmental regulations, 
particularly on the Highlights page, was misleading and not consistent 
with the rest of the report, which has a fuller discussion of many 
factors affecting the future use of coal. EPA stated that market 
changes, which we discuss in the report, would have significant 
impacts even in the absence of EPA's regulations. We do not agree that 
the report was misleading, but given that the Highlights page may be 
read without the benefit of the fuller discussion found in the report, 
we moved language from the body of the report to the Highlights page 
about other factors affecting the use of coal. EPA provided other 
technical comments, which we incorporated where 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 Administrators of the EIA 
and 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 me at (202) 512-3841 or r [Hyperlink, ruscof@gao.gov] 
uscof@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 III. 

Sincerely yours, 

Signed by: 

Frank Rusco: 
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Analysis of Characteristics of Coal-Fueled Generating 
Units That Power Companies Plan to Retire: 

This appendix describes our statistical analysis of characteristics of 
coal-fueled electricity generating units, such as age and size, that 
are likely to affect power companies' plans to retire certain units. 
We use this analysis to estimate the number and generating capacity of 
other coal-fueled units that power companies are likely to consider 
retiring. 

Methodology: 

To test the hypothesis that power companies are likely to retire 
older, smaller, and more polluting coal units by 2020, we used 
logistic regression analysis. We analyzed industry data on all coal-
fueled units owned by power companies that have already announced 
plans to retire one or more of these units. Using unit-and company-
level data, primarily from company-reported databases, we developed a 
model depicting the relationship between companies' announced plans to 
retire a unit and that unit's characteristics--age, size, emissions 
rates of sulfur dioxide (SO2) and nitrogen oxides (NOx), and the 
regulatory status of the power company that owns the unit, 
specifically whether the company is traditionally regulated or 
operates in a restructured market. To estimate the number and 
generating capacity of additional units likely to be retired, we 
applied our model to a dataset consisting of coal-fueled units owned 
by power companies that have not announced any retirements. 

Model of Plans to Retire Coal-Fueled Generating Units: 

In developing our model of power companies' plans to retire coal-
fueled units, we relied on economic theory, as well as discussions 
with stakeholders and our review of studies. Stakeholders included 
representatives from power companies, a coal company, industry 
associations, and nongovernmental organizations, and officials from 
federal and state agencies. Stakeholders and studies mentioned the 
following characteristics as likely unit-level determinants of power 
companies' plans to retire a coal-fueled unit or keep it in operation: 

* age; 

* generating capacity; 

* fuel efficiency (i.e., how efficiently a unit converts fuel to 
electricity): 

* operating cost and profitability; 

* pollution emission rates and whether a unit already has various 
types of emissions control equipment; and: 

* regulatory status. 

As a general matter, the larger, newer, more efficient, and less 
polluting a generating unit is, the more likely it is that a power 
company may to want to keep it in service and invest in retrofits that 
may be needed for it to comply with environmental laws or regulations. 
For example, if a large, new generating unit that a power company uses 
to meet a significant portion of customer demand is not in compliance 
with environmental regulations, retiring it would likely require 
replacing it with another unit of similar size. Doing so may be very 
costly, and retrofitting it with the requisite pollution control 
equipment may be a more economical choice. 

It is also reasonable to expect regulatory status to have some impact 
on power companies' retirement plans because such plans could involve 
significant investments. For companies that are traditionally 
regulated, state public utility commissions review power companies' 
plans for major investments in pollution control equipment in the case 
of a retrofit, or in replacement power generation capacity if it is 
needed after a unit is retired. Decisions by power companies in 
restructured markets are not subject to the same state public utility 
oversight. Furthermore, once state public utility commissions approve 
a traditionally regulated company's plan to invest in major retrofits 
or replacement units, they allow it to charge rates to recover its 
investment costs. Companies operating in restructured markets have no 
such cost-recovery provisions, so their investments in retrofits or 
replacement units may be riskier. 

Our model does not include all the characteristics that stakeholders 
and studies identified as possible characteristics that power 
companies consider in deciding which coal-fueled units to retire. 
First, economic theory and our analysis of data on coal-fueled units 
indicate that there are interrelationships among some of these 
characteristics; for example, newer, larger electric generating units 
tend to be more fuel efficient, and this fuel efficiency contributes 
to lower operating costs. Hence, including all characteristics would 
be redundant and weaken the statistical results. Below, we discuss 
some specifications of the model with alternative sets of variables. 
Second, there are likely other characteristics that may influence 
power companies' plans to retire generating units that we were unable 
to include in our statistical analysis. We discuss limitations of our 
model below. 

Data Used: 

We used U.S. electricity data at the level of individual coal-fueled 
generating units that we obtained under contract from Ventyx,[Footnote 
37] a company that maintains a proprietary database containing 
consolidated energy and emissions data from the Energy Information 
Administration (EIA),[Footnote 38] the Environmental Protection Agency 
(EPA), and other sources. In particular, we relied primarily on two 
datasets from Ventyx, "Generating Unit Capacity," and "Unit Generation 
& Emissions - Annual," from which we assembled our dataset of 
characteristics of operating coal-fueled generating units. These 
characteristics included some of the following: 

* generating unit identification data, including name of power company 
owning the unit, location, and unit identification numbers; 

* proposed retirement year; 

* age; 

* size, measured in megawatts (MW) of generating capacity; 

* fuel efficiency; 

* emissions rates of SO2, NOx, and carbon dioxide; 

* types of installed control equipment or whether owners plan to 
install control equipment in the future; 

* various cost measures, including generating unit marginal cost; and: 

* regulatory status: equals 1 if the power company that owns the unit 
was traditionally regulated or 0 if the company was operating in a 
restructured market.[Footnote 39] 

We also used regional day-ahead market prices from the 
Intercontinental Exchange (ICE) company, and spot market prices from 
the Federal Energy Regulatory Commission (FERC) to calculate an 
average wholesale market price for the regional markets associated 
with each unit in our dataset.[Footnote 40] For each market region, we 
calculated a simple average of daily prices for the year 2011 from 
daily ICE price data. For some of the regions, however, there were no 
price data available from ICE, so we used the 2011 average spot market 
price from FERC.[Footnote 41] 

While our model does not include all the aforementioned 
characteristics, we used most of these characteristics in alternative 
specifications of the model and discuss two of these specifications 
below. 

Our complete dataset includes 959 coal-fueled units. This dataset 
includes only units that have a net summer generating capacity greater 
than 25 MW, making them subject to EPA emissions monitoring and 
reporting requirements. We excluded units that have not reported any 
electricity generation or SO2 or NOx emissions over the past 5 years. 
[Footnote 42] Of the total 959 units, 482 units belong to power 
companies that have announced plans for retiring at least one coal-
fueled unit. 

Results: 

We used logistic regression (logit) analysis to analyze the 
characteristics that are affecting power companies' retirement plans 
of coal-fueled electricity generation units. Regression analysis in 
general estimates the effect of a change in an independent variable on 
the outcome (dependent) variable, while holding other variables 
constant. Logit is a type of regression analysis for situations in 
which the dependent variable is a categorical variable--one that can 
take on a limited number of values--instead of a continuous, 
quantitative variable. In this case, the categorical variable is 
binary, which means that the choice is between only two outcomes. 

We estimated the logit regression equation for the subgroup of 482 
coal-fueled generating units belonging to power companies that have 
announced plans to retire at least one coal-fueled unit. The dependent 
variable in our model is whether to retire or not retire a coal unit, 
and the independent variables are the (1) age of unit; (2) net summer 
capacity as a measure of unit size; (3) unit's SO2 emissions rate in 
pounds (lb) of SO2 emissions per unit of heat input from the fuel used 
in the unit's electricity generation, measured using millions of 
British thermal units (Btu); (4) unit's NOx emissions rate in lb/ 
million Btu; (5) whether the power company that owns the unit is 
traditionally regulated or operates in a restructured market. 

Table 2 shows our resulting estimated equation and relevant statistics. 

Table 2: Regression Results of Characteristics Associated with Planned 
Coal-Fueled Unit Retirements-Dependent Variable Is the Probability of 
a Unit Retirement Announcement: 

Variable: Net summer capacity; 
Coefficient: -0.00198; 
Standard error: 0.0010; 
Significance[A]: 5.9%. 

Variable: Unit age; 
Coefficient: 0.06647; 
Standard error: 0.0201; 
Significance[A]: 0.1%. 

Variable: SO2 emissions rate; 
Coefficient: 0.68053; 
Standard error: 0.1550; 
Significance[A]: 0.0%. 

Variable: NOx emissions rate; 
Coefficient: 3.64861; 
Standard error: 0.9168; 
Significance[A]: 0.0%. 

Variable: Regulatory status; 
Coefficient: -1.56564; 
Standard error: 0.3331; 
Significance[A]: 0.0%. 

Variable: Constant; 
Coefficient: -3.84944; 
Standard error: 1.3276; 
Significance[A]: 0.4%. 

Source: GAO analysis of Ventyx data: 

Note: Number of observations equals 482. 

[A] Significance is measured by the probability that we would find 
these results if the true value of the coefficient were zero. A lower 
significance level means that it is less likely that the observed 
pattern in the data is the product of pure chance. As with any 
regression, the statistical significance depends on the model being 
correctly specified. 

[End of table] 

These results generally confirm that smaller, older and more polluting 
units are more likely candidates for retirement. In the table above, 
the second column gives the estimated value of the coefficient, which 
describes the relationship between the independent variables and the 
likelihood of retirement. The remaining columns give the standard 
error and the significance level. For example, the coefficient on net 
summer capacity is negative, which means that an increase in capacity 
decreases the probability that a unit is planned for retirement. 
Furthermore, as shown in table 2, the estimated coefficient is 
significant at the 6 percent level. An estimated coefficient is 
typically considered statistically significant if the significance is 
less than 10 percent and very significant if it is less than 5 
percent. Similarly, the coefficient on unit age is positive, which 
means that an older unit is more likely to be retired, and this 
coefficient estimate is significant at the 1 percent level. The 
coefficients on SO2 and NOx emissions are also positive and 
significant at the 1 percent level. 

Using the resulting logit regression equation, we analyzed "marginal 
effects" of changes in each of the independent variables on plans to 
retire an "average" unit owned by a power company in (1) a 
traditionally regulated market and (2) a restructured market, and the 
"average unit," for this purpose, is one with median values for age, 
size/net summer capacity, SO2, and NOx emissions rates, as shown in 
tables 3 and 4. 

Table 3: Effect of 10% Change in a Variable Value on the Probability 
of an Average Unit's Planned Retirement When Owned by a Power Company 
in a Restructured Marked: 

Variable name: Net summer capacity (size of unit); 
Median value of variable: 193; 
Value with 10% change: 212; 
Change in probability of retirement: -2%. 

Variable name: Age of unit; 
Median value of variable: 43; 
Value with 10% change: 47; 
Change in probability of retirement: 7%. 

Variable name: Unit's SO2 emissions rate; 
Median value of variable: 0.49; 
Value with 10% change: 0.54; 
Change in probability of retirement: 1%. 

Variable name: Unit's NOx emissions rate; 
Median value of variable: 0.20; 
Value with 10% change: 0.22; 
Change in probability of retirement: 2%. 

Source: GAO analysis of Ventyx data. 

[End of table] 

Table 4: Effect of 10% Change in a Variable Value on the Probability 
of an Average Unit's Planned Retirement When Owned by a Traditionally 
Regulated Power Company: 

Variable name: Net summer capacity (size of unit); 
Median value of variable: 230; 
Value with 10% change: 253; 
Change in probability of retirement: -1%. 

Variable name: Age of unit; 
Median value of variable: 43; 
Value with 10% change: 47; 
Change in probability of retirement: 4%. 

Variable name: Unit's SO2 emissions rate; 
Median value of variable: 0.57; 
Value with 10% change: 0.63; 
Change in probability of retirement: 1%. 

Variable name: Unit's NOx emissions rate; 
Median value of variable: 0.23; 
Value with 10% change: 0.25; 
Change in probability of retirement: 1%. 

Source: GAO analysis of Ventyx data. 

[End of table] 

For example, a 10 percent increase in the capacity of an average unit 
owned by a power company in a restructured market, from 193 to 212 MW, 
would decrease the probability of that unit's retirement by about 2 
percent, all other variables being held constant. For a unit owned by 
a power company in a traditionally regulated market, the same 10 
percent would decrease the probability of retirement by about 1 
percent. Note that the median values for units owned by power 
companies operating in traditionally regulated and restructured 
markets are not the same and that a 10 percent increase is therefore 
different.[Footnote 43] 

Analysis Indicates Units Power Companies Likely to Consider Retiring: 

The next step in our analysis was to use the resulting logit 
regression equation to estimate the number and generating capacity of 
other coal-fueled units that companies are likely to consider retiring 
among units belonging to companies that have not, as of yet, announced 
plans to retire coal-fueled units. We also estimated the generation 
associated with these potential retirements in megawatt-hours (MWh). 
We assume that some or all of these companies are likely to retire 
coal-fueled units, but that they either have not decided which ones, 
or simply have not publicly announced their plans. We further assume 
that these companies have or will base their decisions on the same 
characteristics as the companies that have already made announcements. 
Table 5 shows our analysis of units that power companies may consider 
for retirement by 2020. 

Table 5: Coal-Fueled Units That Companies May Consider for Retirement 
by 2020: 

All units: 

Number; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 482; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 477; 
Total coal-fueled units: 959. 

Net summer capacity; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 158,000 MW; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 148,000 MW; 
Total coal-fueled units: 306,000 MW. 

Units planned for retirement or that may be considered for retirement: 

Number; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 174; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 90 to 138; 
Total coal-fueled units: 264 to 312. 

Net summer capacity; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 30,400 MW; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 15,700 to 25,200 MW; 
Total coal-fueled units: 46,100 to 55,600 MW. 

Net summer capacity as percent of all units; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 19%; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 11 to 17%; 
Total coal-fueled units: 15% to 18%. 

Generation; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 150 million MWh; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 91 to 151 million MWh; 
Total coal-fueled units: 241 to 301 million MWh. 

Generation as a percent of all units; 
Units owned by companies that have announced at least one coal-fueled 
unit retirement: 16%; 
Units owned by companies that have announced no coal-fueled unit 
retirements: 10 to 16%; 
Total coal-fueled units: 13 to 16%. 

Source: GAO analysis of Ventyx data . 

Note: We include only units from the Ventyx databases that have 
reported electricity generation and SO2 emissions greater than zero 
during any of the years 2008 through 2012, and with net summer 
generating capacity greater than 25 MW. We rounded capacity numbers to 
the nearest 100 MW and generation to the nearest million MWh. 
Generation is based on annual average generation 2007-2011. 

[End of table] 

As shown in table 5, for the group of coal-fueled units whose owners 
have not reported any coal-fueled unit retirements, our analysis 
indicates from 90 to 138 units may likely be considered for retirement 
by 2020. This range represents the 95 percent confidence interval 
around our point estimate of 114 units. In other words, our model 
indicates that there is a 95 percent probability that the actual 
number of units that will retire is within this range. These 90 to 138 
units account for 15,700 to 25,200 MW of capacity and 91 to 151 
million MWh of electricity generation. If we add these units to those 
that power companies have announced for retirement, the total of coal-
fueled retirements could range from 264 to 312 units by 2020, 
amounting to from 46,100 to 55,600 MW of capacity and average annual 
generation of 241 to 301 million MWh.[Footnote 44] In percentage 
terms, this would be 15 to 18 percent of the capacity and 13 to 16 
percent of the generation of the current coal-fueled fleet of 
generating units. 

Limitations and Alternative Model Specifications: 

This section discusses the limitations of our model and alternative 
model specifications that we tested. 

Limitations: 

A major limitation of our model is that we used a nonrandom sample of 
the entire population of coal-fueled units to estimate the 
relationship between the characteristics of coal-fueled units and 
power companies' plans to retire a unit. Our sample consisted of 
companies that announced plans to retire at least one unit but was not 
a random sample. It is possible that the companies that announced 
planned retirements and those that did not so announce differ in 
systematic ways that we do not observe from the data.[Footnote 45] 
Such differences could result in omitted variable bias. 

Another important limitation of our model is that we did not include 
all factors that contribute to power companies' decision to retire 
coal-fueled units. Apart from unit-level considerations, major factors 
that affect a power company's decision to retire a coal-fueled unit 
include fuel costs, environmental regulations, regional and local 
market considerations (e.g., expected future electricity demand and 
supply conditions, and transmission constraints), and technological 
developments in electricity generation and pollution control. For 
example, we did not take into account that planned unit retirements 
might make otherwise marginal units in some regions more valuable and 
less likely to retire. Companies that own coal-fueled units may have 
different expectations regarding these factors, which we did not 
consider in our analysis.[Footnote 46] Effectively, therefore, we 
assumed that power companies have very similar expectations regarding 
these factors. 

These above limitations could mean that our model does not accurately 
or fully reflect power companies' unit retirement decisions. This 
would also mean that our estimates of how many unannounced units will 
retire may be inaccurate. For most of the limitations, the direction 
of bias in our model--the extent to which it may over-or under-
estimate the likelihood of a unit retiring--is unclear. Addressing 
these limitations was beyond the scope of our review. 

Alternative Specifications: 

To check the robustness of our model, we tested different 
specifications; that is, we ran logistic regressions using different 
sets of independent variables. For example, we tried specifications 
that included a measure of a unit's fuel efficiency, and another 
representing whether a unit is planning to install pollution control 
equipment. We also tried a version with unit average capacity factors 
in recent years, a measure of how intensively a unit is utilized. 
Based on our results, none of these variables significantly improved 
the model. Below, we discuss two other alternative specifications in 
more detail. 

In one alternative specification, we used clustered standard errors. 
Our model assumes that each individual coal-fueled unit has a unique 
error term that is independent of every other unit. In this 
specification, we allow for the possibility that units owned by the 
same power companies may be related in unobserved ways and, therefore, 
the error terms may be correlated. As shown in table 6, the estimated 
coefficients in this alternative specification are very similar to our 
model, but the standard errors are generally bigger, and the estimated 
coefficients are generally less statistically significant. This is 
especially true for net summer capacity, which is no longer 
statistically significant at the commonly accepted 10 percent level. 

Table 6: Regression Results of Characteristics Associated with Planned 
Coal-Fueled Unit Retirements Using Clustered Standard Errors: 

Variable: Net summer capacity; 
Coefficient: -0.00198; 
Standard error: 0.0014; 
Significance[A]: 14.9%. 

Variable: Unit age; 
Coefficient: 0.06647; 
Standard error: 0.0269; 
Significance[A]: 1.3%. 

Variable: SO2 emissions rate; 
Coefficient: 0.68053; 
Standard error: 0.2041; 
Significance[A]: 0.1%. 

Variable: NOx emissions rate; 
Coefficient: 3.64861; 
Standard error: 1.1659; 
Significance[A]: 0.2%. 

Variable: Regulatory status; 
Coefficient: -1.56564; 
Standard error: 0.3039; 
Significance[A]: 0.0%. 

Variable: Constant; 
Coefficient: -3.84944; 
Standard error: 1.7726; 
Significance[A]: 3.0%. 

Source: GAO analysis of Ventyx data. 

Note: Number of observations equals 482. 

[A] Significance is measured by the probability that we would find 
these results if the true value of the coefficient were zero. A lower 
significance level means that it is less likely that the observed 
pattern in the data is the product of pure chance. As with any 
regression, the statistical significance depends on the model being 
correctly specified. 

[End of table] 

In a second alternative specification, we used adjusted marginal cost 
as a proxy for the profitability of a unit. Based on economic logic 
and what we heard from stakeholders, we expected some indicator of the 
cost and profitability of electricity generation to contribute 
significantly to the retirement decision. Table 7 shows a version with 
marginal cost adjusted for regional wholesale prices and an 
interaction term with marginal cost and regulatory status. We adjusted 
marginal cost by dividing it by the regional wholesale price to 
account for the fact that units are more or less valuable depending on 
regional wholesale electricity prices. The interaction term allows us 
to effectively estimate two coefficients for adjusted marginal cost, 
one for power companies in traditionally regulated markets, and one 
for power companies in restructured markets. We included an 
interaction term to account for the possibility that power companies 
in traditionally regulated and restructured markets view costs 
differently.[Footnote 47] Indeed, as shown in table 7, the estimated 
adjusted marginal cost coefficients differ--for power companies in 
restructured markets, the adjusted marginal cost coefficient is about 
5.8, while the estimated coefficient for power companies in 
traditionally regulated markets is the adjusted marginal cost 
coefficient plus the interaction term (or 5.8 plus -8.2 = -2.4). These 
results suggest that while higher adjusted marginal costs increase the 
probability of retirement of units owned by power companies in 
restructured markets, they decrease the probability for units owned by 
traditionally regulated power companies. The interpretation of these 
results is unclear. 

Table 7: Regression Results of Characteristics Associated with Planned 
Coal-Fueled Unit Retirements Including Adjusted Marginal Cost and 
Interaction Term: 

Variable: Net summer capacity; 
Coefficient: -0.0019; 
Standard error: 0.0011; 
Significance[A]: 8.9%. 

Variable: Unit age; 
Coefficient: 0.0667; 
Standard error: 0.0204; 
Significance[A]: 0.1%. 

Variable: SO2 emissions rate; 
Coefficient: 0.8113; 
Standard error: 0.1763; 
Significance[A]: 0.0%. 

Variable: NOx emissions rate; 
Coefficient: 3.4200; 
Standard error: 0.9328; 
Significance[A]: 0.0%. 

Variable: Adjusted marginal cost; 
Coefficient: 5.8028; 
Standard error: 2.6250; 
Significance[A]: 2.7%. 

Variable: Cost and regulation interaction; 
Coefficient: -8.1719; 
Standard error: 2.7112; 
Significance[A]: 0.3%. 

Variable: Regulatory status; 
Coefficient: 3.1255; 
Standard error: 1.4965; 
Significance[A]: 3.7%. 

Variable: Constant; 
Coefficient: -6.9313; 
Standard error: 2.0123; 
Significance[A]: 0.1%. 

Source: GAO analysis of Ventyx, FERC, and ICE data. 

Note: Number of observations equals 482. 

[A] Significance is measured by the probability that we would find 
these results if the true value of the coefficient were zero. A lower 
significance level means that it is less likely that the observed 
pattern in the data is the product of pure chance. As with any 
regression, the statistical significance depends on the model being 
correctly specified. 

[End of table] 

Regarding the costs of producing electricity, our findings differed 
for companies in restructured markets and companies that are 
traditionally regulated. Specifically, our results suggest that 
companies in restructured markets are more likely to retire units with 
higher adjusted marginal costs. In contrast, our results suggest that 
companies operating in regulated markets are less likely to retire 
units with higher adjusted marginal costs. A number of 
characteristics, not considered in our model, could provide 
alternative explanations for this difference. For example, it could be 
the case that the units in our sample have unique characteristics. One 
such potential case could be that units owned by power companies in 
traditionally regulated markets may be located in areas where concerns 
about the reliability of the electricity system are significant, and 
the costs of retrofitting an older generating unit are less costly 
than retiring it. Similarly, it could be that our sample contains a 
number of units located in areas with lower cost alternative suppliers 
or where prices are low--diminishing the attractiveness of even a 
relatively low-cost unit. 

[End of section] 

Appendix II: Description of Selected Scenarios and Forecasts: 

Table 8 describes key scenarios and assumptions in the EIA, IEA, and 
IHS Global Insight forecasts discussed in this report. 

Table 8: Description of EIA, IHS Global Insight, and IEA Scenarios and 
Forecasts: 

EIA Annual Energy Outlook: 

Scenario: Reference; 
Description: A business-as-usual trend estimate, given known 
technology and technological and demographic trends. Baseline economic 
growth (2.5 percent per year from 2010 through 2035), oil price, and 
technology assumptions; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: 0.1%. 

Scenario: Low coal price; 
Description: Regional productivity growth rates for coal mining are 
approximately 2.8 percent per year higher than in the Reference 
scenario, and coal mining wages, mine equipment, and coal 
transportation rates in 2035 are between 21 and 25 percent lower than 
in the Reference scenario. EIA refers to this as its "Low Coal Cost" 
scenario; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: 0.5%. 

Scenario: High coal price; 
Description: Regional productivity growth rates for coal mining are 
approximately 2.8 percent per year lower than in the Reference 
scenario, and coal mining wages, mine equipment, and coal 
transportation rates in 2035 are between 25 and 27 percent higher than 
in the Reference scenario. EIA refers to this as its "High Coal Cost" 
scenario; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -0.6%. 

Scenario: Low gas price; 
Description: Assumes the well spacing for all tight oil and shale gas 
plays is 8 wells per square mile (i.e., each well has an average 
drainage area of 80 acres) and assumes 50 percent higher recovery for 
tight oil and shale gas wells than in the Reference scenario. Also 
assumes higher reserves of tight oil and shale gas that are more than 
twice the assumptions in the Reference scenario. EIA refers to this as 
its "High Technically Recoverable Resources" scenario; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -0.7%. 

Scenario: High Gas Price; 
Description: Assumes 50 percent lower recovery per tight oil and shale 
gas well than in the Reference scenario, increasing the per-unit cost 
of developing the resource. Also assumes about 50 percent lower 
reserves of tight oil and shale gas than in the Reference scenario. 
EIA refers to this as its "Low Estimated Ultimate Recovery" scenario; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: 0.3%. 

Scenario: $15 Greenhouse Gas Price; 
Description: Applies a price for carbon dioxide emissions throughout 
the economy, starting at $15 per metric ton in 2013 and rising by 5 
percent per year through 2035. In this scenario, carbon dioxide 
emissions from the electric power sector in 2035 would be reduced by 
46 percent from 2010 levels; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -3.5%. 

Scenario: $25 Greenhouse Gas Price; 
Description: Applies a price for carbon dioxide emissions throughout 
the economy, starting at $25 per metric ton in 2013 and rising by 5 
percent per year through 2035. In this scenario, carbon dioxide 
emissions from the electric power sector in 2035 would be reduced by 
76 percent from 2010 levels; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -9.2%. 

Scenario: High Economic Growth; 
Description: Assumes higher growth rate of gross domestic product--an 
average annual rate of 3 percent from 2010 to 2035, compared with 2.5 
percent in the reference case; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: 0.3%. 

Scenario: High Use of Energy Efficient Technologies; 
Description: Assumes all future residential and commercial equipment 
purchases represent the most efficient models available in a 
particular year for each fuel, regardless of cost. EIA refers to this 
as its "Integrated Best Available Demand Technology" scenario; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -1.1%. 

IHS Global Insight: 

Description: A long-term forecast based on a single set of assumptions 
about future energy policies, fuel prices, and other factors. For 
example, IHS Global Insight assumes that a federal greenhouse gas cap-
and-trade program is implemented for the power sector in 2021 but with 
a limit on how high carbon prices could rise; a federal clean energy 
standard is enacted to promote use of electricity generated using 
renewables, nuclear energy, and coal technologies capable of carbon-
capture; and improvements are made in the energy efficiency of 
appliances, equipment and building standards; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -0.5%. 

IEA World Energy Outlook[A]: 

Scenario: Current policies; 
Description: A baseline scenario based on government policies and 
measures enacted by mid-2011; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: 0.8%. 

Scenario: New policies; 
Description: Assumes some future implementation of international 
policy commitments and plans related to climate change, pollution, and 
other energy-related challenges. This includes, for example, 
implementation of EPA regulations to reduce mercury and other 
pollutants in the power sector; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -0.1%. 

Scenario: Scenario 3; 
Description: Assumes future changes consistent with a 17 percent 
reduction in U.S. carbon dioxide emissions in 2020 compared with 2005, 
as well as the implementation of a price on carbon dioxide after 2020 
in the United States. This scenario represents a reduction of U.S. 
carbon dioxide emissions from energy of more than half by 2035 
compared with emissions in 2009; 
Average annual change in electricity produced from coal, 2010-2035 
(percentage)[A]: -3.0%. 

Sources: EIA, IHS Global Insight, IEA. 

[A] IEA data reflect change from 2009 to 2035. 

[End of table] 

[End of section] 

Appendix III: GAO Contact and Staff Acknowledgments: 

GAO Contact: 

Frank Rusco, (202) 512-3841, r [Hyperlink, ruscof@gao.gov] 
uscof@gao.gov: 

Staff Acknowledgments: 

In addition to the contact named above, Jon Ludwigson (Assistant 
Director), Mike Armes, Patrick Dudley, Philip Farah, Quindi Franco, 
Cindy Gilbert, Paige Gilbreath, Alison O'Neill, Kendal Robinson, 
Jeanette Soares, and Kiki Theodoropolous made key contributions to 
this report. 

[End of section] 

Related GAO Products: 

EPA Regulations and Electricity: Better Monitoring by Agencies Could 
Strengthen Efforts to Address Potential Challenges. [hyperlink, 
http://www.gao.gov/products/GAO-12-635]. Washington, D.C.: July 17, 
2012. 

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

Coal Power Plants: Opportunities Exist for DOE to Provide Better 
Information on the Maturity of Key Technologies to Reduce Carbon 
Dioxide Emissions. [hyperlink, 
http://www.gao.gov/products/GAO-10-675]. Washington, D.C.: June 16, 
2010. 

Clean Coal: DOE's Decision to Restructure FutureGen Should Be Based on 
a Comprehensive Analysis of Costs, Benefits, and Risks. [hyperlink, 
http://www.gao.gov/products/GAO-09-248]. Washington, D.C.: February 
13, 2009. 

Climate Change: Federal Actions Will Greatly Affect the Viability of 
Carbon Capture and Storage As a Key Mitigation Option. [hyperlink, 
http://www.gao.gov/products/GAO-08-1080]. Washington, D.C.: September 
30, 2008. 

Restructured Electricity Markets: Three States' Experiences in Adding 
Generating Capacity. [hyperlink, 
http://www.gao.gov/products/GAO-02-427]. Washington, D.C.: May 24, 
2002. 

[End of section] 

Footnotes: 

[1] EIA is a statistical agency within the Department of Energy that 
collects, analyzes, and disseminates independent information on energy 
issues. 

[2] The rest of production was exported or used for other purposes, 
including steel production. In addition to coal, electricity is 
produced using other fossil fuels, particularly natural gas; through 
nuclear fission; and using renewable sources, including hydropower, 
wind, geothermal, and solar energy. 

[3] 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 (MWh) of electricity 
in 1 hour, enough to provide electricity for up to 1 million homes. 
There are many measures of capacity, and we generally refer to net 
summer capacity in this report--a 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 data excludes output used internally for plant 
operations. 

[4] Electricity generation depends on the capacity of generating units 
and how often and to what extent units are operated. 

[5] Compliance with regulations may involve using various technologies 
or making infrastructure changes to reduce adverse impacts; for 
example, installing liners at facilities used to store coal combustion 
wastes to minimize leaching of contaminants into groundwater. 

[6] GAO, EPA Regulations and Electricity: Better Monitoring by 
Agencies Could Strengthen Efforts to Address Potential Challenges, 
[hyperlink, http://www.gao.gov/products/GAO-12-635] (Washington, D.C.: 
July 17, 2012). 

[7] See 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). 

[8] The National Research Council is the principal operating agency of 
both the National Academy of Sciences and the National Academy of 
Engineering. 

[9] In some areas of the country, referred to as "traditionally 
regulated markets," state public utility commissions--which generally 
aim to ensure retail electricity rates are just and reasonable--review 
power companies' requests to recover the costs of investments in new 
generating units, distribution lines, and other system upgrades. Once 
a state public utility commission approves a power company's request, 
consumer retail prices are adjusted to recover the power company's 
costs plus a rate of return. In other areas 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 retail electricity rates based on the price of 
electricity as determined in wholesale markets. 

[10] IEA is an international organization composed of 28 of the member 
nations of the Organisation for Economic Co-operation and Development 
that, among other things, collects energy data and provides research 
and analysis on ways to ensure reliable, affordable, and clean energy. 

[11] IHS Global Insight is a firm that provides comprehensive economic 
and financial information on countries, regions, and industries. 

[12] See [hyperlink, http://www.gao.gov/products/GAO-12-635]. 
Specifically, these include the Cross-State Air Pollution Rule, which 
would have prohibited certain emissions of air pollutants in 28 states 
because of the impact they would have on air quality in other states; 
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, which establishes emissions 
limitations on mercury and other toxic pollutants; the proposed 
Cooling Water Intake Structures at Existing Facilities and Phase I 
Facilities regulation, which would establish requirements for water 
withdrawn and used for cooling purposes that reflect the best 
technology available to minimize adverse environmental impact; and the 
proposed Disposal of Coal Combustion Residuals from Electric Utilities 
regulation, which would govern the disposal of coal combustion 
residuals, such as coal ash, in landfills or surface impoundments. On 
April 13, 2012, EPA also proposed new source performance standards for 
greenhouse gas emissions from certain new fossil fuel electricity 
generating units--including coal-fueled units--but the standards would 
not apply to existing units. 

[13] Specifically, the court issued an opinion that would strike down 
the regulation but has not issued an order striking it down and likely 
will not issue such an order before deciding whether the full court 
will rehear the case. 

[14] See: EIA, Annual Energy Outlook 2012, DOE/EIA-0383 (Washington, 
D.C.: June 2012); IEA, World Energy Outlook 2011 (Paris, France: 
2011); and IHS Global Insight, U.S. Energy Outlook, September 2011. 

[15] Data presented throughout this section refer to units with over 
25 MW of net summer capacity. 

[16] [hyperlink, http://www.gao.gov/products/GAO-12-635]. 

[17] Scrubbers have been used commercially since the early 1970s and 
are the most common technology for reducing SO2 emissions. They are 
capable of removing up to 99 percent of SO2 emissions and work by 
injecting a sorbent--a material used to absorb molecules of a 
substance--into flue gas that reacts with pollutants to form a 
substance that is collected and removed. Scrubbers can also reduce 
emissions of mercury and other air pollutants. Another approach to 
reducing SO2 emissions from coal-fueled electricity generating units 
is to switch from using coal with a higher sulfur content to coal with 
a lower sulfur content or to blend higher-sulfur coal with lower-
sulfur coal. However, according to studies we reviewed, power 
companies may install scrubbers or other new control equipment to meet 
the requirements of new regulations. 

[18] Specifically, according to the EPA report, capital costs could 
range from $385,000 to $470,000 per MW for a 700 MW unit, and from 
$641,000 to $817,000 per MW for a 100 MW unit. See: EPA, Documentation 
for EPA Base Case v.4.10 Using the Integrated Planning Model, 
EPA#430R10010 (Washington, D.C.: August 2010). 
[http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html]. 

[19] A Btu is a measure of energy that is the heat required to raise 
the temperature of 1 pound of water by 1 degree Fahrenheit. 

[20] Specifically, we applied the results of our statistical analysis 
to units owned by power companies that have not made retirement 
announcements, assuming that they may still be assessing their options 
to identify units for retirement. We assume that companies that have 
announced some retirements have effectively announced all the units 
they plan to retire. See appendix I for additional information on our 
analysis. 

[21] Specifically, we identified the 95 percent confidence interval in 
that our analysis suggests that there is a 95 percent probability that 
the actual number of units that may retire is within this range. 

[22] See [hyperlink, http://www.gao.gov/products/GAO-12-635]. 

[23] Similarly, the 10 cleanest coal-fueled units emitted 24 percent 
more NOx and 79 percent more CO2 per million Btu than the average 
combined cycle natural gas unit. Many natural gas-fueled units built 
recently have used highly efficient combined-cycle technologies, which 
rely on large gas turbines, also called combustion turbines, together 
with a steam generator and a steam turbine to convert waste heat in 
the exhaust stream to electricity. 

[24] GAO, Restructured Electricity Markets: Three States' Experiences 
in Adding Generating Capacity, [hyperlink, 
http://www.gao.gov/products/GAO-02-427] (Washington, D.C.: May 24, 
2002). 

[25] As discussed, a number of generating units are expected to be 
retired in the future, and these tend to be smaller units. Of the 
operating fleet, the average size of units planned for retirement is 
175 MW, and the average size of units without retirement plans is 351 
MW. 

[26] The New Source Review provisions of the Clean Air Act establish 
this permitting process. See [hyperlink, 
http://www.gao.gov/products/GAO-12-545R]. 

[27] As mentioned, coal's share of total electricity generating 
capacity was about 30 percent in 2011 and is expected to decline, 
according to EIA's reference scenario, to 25 percent in 2035 as 
retiring coal-fueled generating units are replaced with few new coal-
fueled units. 

[28] Generation is based on annual average generation 2007-2011. 

[29] Of the three estimates we reviewed, EIA was the only one that 
provided information on the location of coal production in the United 
States. 

[30] [hyperlink, http://www.gao.gov/products/GAO-12-635]. 

[31] Stakeholders provided various examples of current environmental 
and other regulations with the potential to affect the coal industry 
in the future, including 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, which establishes emissions limitations on mercury and 
other toxic pollutants. Stakeholders also discussed the proposed 
Cooling Water Intake Structures at Existing Facilities and Phase I 
Facilities regulation, which would establish requirements for water 
withdrawn and used for cooling purposes that reflect the best 
technology available to minimize adverse environmental impact and the 
proposed Disposal of Coal Combustion Residuals from Electric Utilities 
regulation, which would govern the disposal of coal combustion 
residuals, such as coal ash, in landfills or surface impoundments. 

[32] EPA has taken actions to regulate greenhouse gas emissions from 
electricity generating units. Specifically, since 2011, EPA 
regulations have required permits for greenhouse gas emissions from 
certain new and existing units. In addition, under the terms of a 
settlement agreement, EPA was required to propose and finalize new 
source performance standards for greenhouse gas emissions from new and 
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. 

[33] In 2008, we reported on the key economic, legal, regulatory, and 
technological barriers impeding commercial-scale deployment of carbon 
capture and storage technology and actions certain federal agencies 
are taking to overcome these barriers. GAO, Climate Change: Federal 
Actions Will Greatly Affect the Viability of Carbon Capture and 
Storage As a Key Mitigation Option, [hyperlink, 
http://www.gao.gov/products/GAO-08-1080] (Washington D.C.: Sept. 30, 
2008). In 2010, we reported on the maturity, commercial viability, and 
implications of technologies to reduce carbon dioxide from coal power 
plants. GAO, Coal Power Plants: Opportunities Exist for DOE to Provide 
Better Information on the Maturity of Key Technologies to Reduce 
Carbon Dioxide Emissions, [hyperlink, 
http://www.gao.gov/products/GAO-10-675] (Washington, D.C.: June 16, 
2010). 

[34] Under the first scenario, IEA estimates a reduction of U.S. CO2 
emissions from energy of 12 percent by 2035 compared with emissions in 
2009. The second scenario represents a reduction of U.S. CO2 emissions 
from energy of more than half by 2035 compared with emissions in 2009. 

[35] 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. 

[36] EIA, Analysis of the Clean Energy Standard Act of 2012 
(Washington, D.C.: May 2012). 

[37] Ventyx is an operating unit of the ABB Company. 

[38] EIA is a statistical agency within the Department of Energy that 
collects, analyzes, and disseminates independent information on energy 
issues. 

[39] In its datasets, Ventyx uses the term "unregulated" instead of 
the term we use, "restructured." We use the term "restructured" 
because all generating units are subject to some type of government 
regulation, even if they are not traditionally regulated. A limited 
number of coal-fueled units in our sample are jointly owned by two or 
more companies with at least one owner being traditionally regulated 
and at least one other operating in a restructured market. In these 
cases, we designated the unit owner's regulatory status according to 
the majority owner. In the case of two power companies owning six 
units, ownership was 50/50 between companies that were traditionally 
regulated and those operating in a restructured market. In this case, 
we decided to use the designation traditionally regulated for the 
power company's regulatory status. 

[40] ICE is a company that offers commodity trading services in 
energy, agriculture, and other sectors. ICE day-ahead electricity 
prices are publicly available on ICE's website. While the Ventyx 
datasets to which we had access do not include regional wholesale 
electricity price data, they do indicate the ICE electricity market 
regions (referred as "hubs") relevant to each of the units in the 
datasets that we used. The prices that FERC reports are based on data 
from Platt's, a leading provider of commodity markets data. 

[41] We compared the average 2011 prices from the ICE data source and 
from FERC for the regions that both sources reported, and they were 
extremely close. 

[42] Net summer capacity is a 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 
excludes output used internally for plant operations. 

[43] Note that marginal effects must be calculated for a given unit. 
We choose the median values for each variable, but other values could 
have been chosen. Unlike a linear regression analysis, the marginal 
effect of a logistic regression analysis depends on the value of all 
of the variables. This is a general feature and prevents the predicted 
probabilities from being greater than one or less than zero. 

[44] We base our estimate of the expected loss of generation due to 
these retirements on generation from units in our dataset for the 
years 2007-2011. 

[45] In addition, we could not distinguish between two types of power 
companies with no announced planned retirements: (1) on the one hand, 
companies that may actually have some plans to retire some of their 
coal-fueled units but, for one reason or another, have no incentive to 
make their plans public and (2) companies that have actually decided 
not to retire any of their units. In our dataset, both companies would 
be labeled "unannounced." 

[46] To do so would have required an extensive survey of power 
companies, which was beyond the scope of our review. 

[47] State public utility commissions review the costs of 
traditionally regulated power companies and also review the prices 
that they charge for the electricity that they sell to their 
customers, while companies that operate under restructured markets are 
more directly exposed to market conditions governing costs and prices. 

[End of section] 

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