ELECTRICITY

Significant Changes 

Are Expected in CoalFueled Generation, 

but Coal is Likely to 

Remain a Key Fuel 

Source

Report to the Chairman, Committee on 

Commerce, Science, and 

Transportation, U.S. Senate

October 2012

GAO-13-72

United States Government Accountability Office

GAO
United States Government Accountability Office

Highlights of GAO-13-72, a 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

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 

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. Power companies may also 

retrofit some units by installing controls 

to reduce pollutants. 

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 analysis. GAO’s 

statistical analysis, examining data on power companies that have announced 

plans to retire coal-fueled units, 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. Based 

on the characteristics of the units companies plan to retire, GAO estimated 

additional capacity that may retire. In total, GAO identified 15 to 18 percent of 

coal-fueled capacity that power companies either plan to retire or that GAO 

estimated may retire—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 in the future 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 amount of electricity generated using coal 

is expected to remain relatively constant through 2035, but it 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. 

EPA provided technical comments that were incorporated as appropriate.

View GAO-13-72. For more information, 

contact Frank Rusco at (202) 512-3841 or 

ruscof@gao.gov. 
Page i GAO-13-72 Electricity

Letter 1 

Background 5

Retirements, Retrofits, and New Construction May Result in a 

Smaller but Cleaner Coal-Fueled Electricity Generating Fleet 10

Coal Likely to Remain a Key Fuel Source, but Future Use May Be 

Affected by Fuel Prices, Environmental Regulations, and Other 

Factors 21

Agency Comments and Our Evaluation 31

Appendix I Analysis of Characteristics of Coal-Fueled Generating Units That Power 

Companies Plan to Retire 33

Methodology 33

Results 36

Analysis Indicates Units Power Companies Likely to Consider 

Retiring 39

Limitations and Alternative Model Specifications 41

Appendix II Description of Selected Scenarios and Forecasts 45

Appendix III GAO Contact and Staff Acknowledgments 47

Related GAO Products 48

Tables

Table 1: Results of EIA Alternate Fuel Price Scenarios 27

Table 2: Regression Results of Characteristics Associated with 

Planned Coal-Fueled Unit Retirements–Dependent 

Variable Is the Probability of a Unit Retirement 

Announcement 37

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 38

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 38

Contents
Page ii GAO-13-72 Electricity

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

Retirement by 2020 40

Table 6: Regression Results of Characteristics Associated with 

Planned Coal-Fueled Unit Retirements Using Clustered 

Standard Errors 43

Table 7: Regression Results of Characteristics Associated with 

Planned Coal-Fueled Unit Retirements Including Adjusted 

Marginal Cost and Interaction Term 44

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

and Forecasts 45

Figures

Figure 1: Coal Production and Employment, 1960-2011 5

Figure 2: Electricity Generation from Coal, 1960-2010 6

Figure 3: U.S. Coal Exports by Destination, 2001-2011 9

Figure 4: Capacity of Coal-Fueled Units by Year of First 

Commercial Operation and Planned Retirements 12

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

Capacity Category 14

Figure 6: Number of Coal-Fueled Electricity Generating Units by 

2011 SO2 Emissions Rate 16

Figure 7: Capacity of Planned Coal-Fueled Electricity Generating 

Units by Status, as of July 26, 2012 19

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

Generating Capacity 20

Figure 9: EIA’s Reference Scenario Projections of Electricity 

Generation by Fuel 22

Figure 10: Actual 2010 and EIA’s Reference Scenario Projected 

2035 Coal Production by Region 24

Figure 11: Actual and Projected Coal and Natural Gas Prices 26
Page iii GAO-13-72 Electricity

Abbreviations

Btu British thermal unit

CO2

EIA Energy Information Administration

carbon dioxide

EPA Environmental Protection Agency

IEA International Energy Agency 

MW megawatt

MWh megawatt-hour

NOx

SO

 nitrogen oxides

2

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

without further permission from GAO. However, because this work may contain 

copyrighted images or other material, permission from the copyright holder may be 

necessary if you wish to reproduce this material separately.

sulfur dioxide
Page 1 GAO-13-72 Electricity

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).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.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 

electricity3

—about 30 percent of total generating capacity in the United 

States. These coal-fueled units generated 42 percent of the nation’s 

electricity in 2011.4

 

1

EIA is a statistical agency within the Department of Energy that collects, analyzes, and 

disseminates independent information on energy issues.

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, 

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 megawatthours (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. 

 
 

Page 2 GAO-13-72 Electricity

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.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.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.

7 The National Research Council8

 

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. 

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. 

6

GAO, EPA Regulations and Electricity: Better Monitoring by Agencies Could Strengthen 

Efforts to Address Potential Challenges, GAO-12-635 (Washington, D.C.: July 17, 2012). 

7

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

Page 3 GAO-13-72 Electricity

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 coalfueled 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).9

 

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.

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 
 

Page 4 GAO-13-72 Electricity

(IEA)10 and IHS Global Insight,11

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.

and summarized projections of coalfueled 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.

 

10IEA 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.

11IHS Global Insight is a firm that provides comprehensive economic and financial 

information on countries, regions, and industries.
 

Page 5 GAO-13-72 Electricity

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

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 

Background 
 

Page 6 GAO-13-72 Electricity

fuels, and other reasons. (See fig. 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

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

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 
 

Page 7 GAO-13-72 Electricity

with coal-fueled electricity generating units.12

 

12See 

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 coalfueled 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 

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.
 

Page 8 GAO-13-72 Electricity

emissions.

13

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.

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.

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.

 

13Specifically, 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. 
 

Page 9 GAO-13-72 Electricity

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

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.14

 

14See: 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.

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, 
 

Page 10 GAO-13-72 Electricity

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.

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.

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 2011.15

 

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

capacity.

As we have previously reported, this 

Retirements, 

Retrofits, and New 

Construction May 

Result in a Smaller 

but Cleaner CoalFueled Electricity 

Generating Fleet

Power Companies Are 

Planning to Retire a 

Significant Number of 

Older, Smaller, More 

Polluting Units
 

Page 11 GAO-13-72 Electricity

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 2012.16

• 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.

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.)

 

16GAO-12-635. 
 

Page 12 GAO-13-72 Electricity

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

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.

• Smaller. The smaller a unit is, the more likely a power company is to 

be planning to retire it. (See fig. 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 
 

Page 13 GAO-13-72 Electricity

desulfurization units—known as scrubbers—to control SO2 and other 

air emissions.17 According to an EPA report, a typical 100 MW coalfueled unit could incur capital costs 66 to 74 percent higher per MW to 

install a scrubber than a 700 MW unit.18

 

17Scrubbers 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.

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.

18Specifically, 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) 
 

Page 14 GAO-13-72 Electricity

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

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.

• 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 
 

Page 15 GAO-13-72 Electricity

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 fig. 6).19 Similarly, units planned for retirement 

emitted on average about 60 percent more NOx and 1 percent more 

CO2

 

19A Btu is a measure of energy that is the heat required to raise the temperature of 1 

pound of water by 1 degree Fahrenheit. 

than units not planned for retirement.
 

Page 16 GAO-13-72 Electricity

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

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.

Emissions Rate

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 
 

Page 17 GAO-13-72 Electricity

units and associated generating capacity that power companies may 

consider retiring.20 Our analysis is subject to some uncertainty, and we 

therefore identified a range of units that power companies may consider 

retiring.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.

As we reported in July 2012, power companies may retrofit many coalfueled electricity generating units with new or upgraded pollution control 

equipment in response to new environmental regulatory requirements.22

 

20Specifically, 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.

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 onethird 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 coalfueled 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 least21Specifically, 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. 

22See GAO-12-635. 

Many Units May Be 

Retrofitted with Pollution 

Control Equipment
 

Page 18 GAO-13-72 Electricity

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.23 Electricity generating units 

that rely on solar and wind sources produce no such emissions.

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 fig. 7). However, as we have previously reported, 

developers generally have more planned projects than they complete.24

 

23Similarly, 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.

24GAO, Restructured Electricity Markets: Three States' Experiences in Adding Generating 

Capacity, GAO-02-427 (Washington, D.C.: May 24, 2002). 

Some New Generating 

Units May Be Built and 

Would Be Larger, Cleaner, 

and More Efficient Than 

the Fleet Overall
 

Page 19 GAO-13-72 Electricity

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

of July 26, 2012

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.

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 coalfueled 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 
 

Page 20 GAO-13-72 Electricity

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

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.25

 

25As 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. 

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 
 

Page 21 GAO-13-72 Electricity

control technologies such as scrubbers to reduce emissions of SO2.

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 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.

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 2011.27

 

26The New Source Review provisions of the Clean Air Act establish this permitting 

process. See 

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.

GAO-12-545R. 

27As 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.

Coal Likely to Remain 

a Key Fuel Source, 

but Future Use May 

Be Affected by Fuel 

Prices, Environmental 

Regulations, and 

Other Factors

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 
 

Page 22 GAO-13-72 Electricity

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

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.

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 coalfueled generating units in the future, but these retirements may have 
 

Page 23 GAO-13-72 Electricity

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.

28

The changes in coal use may also result in shifts between major coalproducing 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.

(See app. I for additional information on 

our statistical analysis.) 

29

 

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

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. 

29Of the three estimates we reviewed, EIA was the only one that provided information on 

the location of coal production in the United States. 
 

Page 24 GAO-13-72 Electricity

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

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 
 

Page 25 GAO-13-72 Electricity

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.

According to available information, the future use of coal to generate 

electricity in the United States may be determined by several key factors.

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 coalfueled 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 

Future Fuel Prices, 

Environmental 

Regulations, and Other 

Factors May Affect the Use 

of Coal in the United 

States 

Prices for Natural Gas and 

Other Competing Fuels
 

Page 26 GAO-13-72 Electricity

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.30

Figure 11: Actual and Projected Coal and Natural Gas Prices

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.

Note: Shading is not indicative of projected prices between 2012 and 2035. As described, 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 coalfueled 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. Data for the low price scenarios were 

obtained from EIA’s “High Total Recoverable Resources” and “Low Coal Cost” scenarios. Data were 

converted to 2012 year dollars using the gross domestic product deflator based on the calendar year.

a

 

30

Average through June 2012.

GAO-12-635. 
 

Page 27 GAO-13-72 Electricity

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

Electricity 

generated 

using coal 

(million 

MWh)

Average annual 

percent change in 

electricity 

generated using 

coal, 2010–2035 

(percentage) 

Share of total 

electricity 

generated using 

coal

Actual, 2010 1,851 Not applicable 45

Actual, 2011 1,734 Not applicable 42

Reference Scenario, 2035 1,897 0.1 % 38

Scenario with High Coal 

Prices, 2035 1,577 -0.6% 32

Scenario with Low Coal 

Prices, 2035 2,107 0.5% 42

Scenario with High Natural 

Gas Prices, 2035 1,977 0.3% 40

Scenario with Low Natural 

Gas Prices, 2035 1,542 -0.7% 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.

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 

Current and Future 

Environmental Regulations and 

Renewable Energy Policies
 

Page 28 GAO-13-72 Electricity

coal.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.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.33

Though it is unclear whether there will be additional future efforts to 

reduce CO2 emissions, EIA assessed two scenarios examining 

 

31Stakeholders 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.

32EPA 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.

33In 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, 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, GAO-10-675 (Washington, D.C.: June 16, 2010). 
 

Page 29 GAO-13-72 Electricity

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.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.35

 

34Under 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.

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 

35These 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. 
 

Page 30 GAO-13-72 Electricity

demand for renewables and other sources favored by these rules and 

diminish demand for electricity from coal.36

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.

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 

 

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

Demand for Electricity 

Other Factors 
 

Page 31 GAO-13-72 Electricity

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.

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 coalexporting 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).

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 

Extent of Future Coal 

Exports Is Uncertain

Agency Comments

and Our Evaluation 
 

Page 32 GAO-13-72 Electricity

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 http://www.gao.gov. 

If you or your staff members have any questions about this report, please 

contact me at (202) 512-3841 or ruscof@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,

Frank Rusco

Director, Natural Resources and Environment
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 33 GAO-13-72 Electricity

This appendix describes our statistical analysis of characteristics of coalfueled 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.

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.

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.

Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Methodology 

Model of Plans to Retire 

Coal-Fueled Generating 

Units 
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 34 GAO-13-72 Electricity

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.
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 35 GAO-13-72 Electricity

We used U.S. electricity data at the level of individual coal-fueled 

generating units that we obtained under contract from Ventyx,1 a 

company that maintains a proprietary database containing consolidated 

energy and emissions data from the Energy Information Administration 

(EIA),2

• generating unit identification data, including name of power company 

owning the unit, location, and unit identification numbers;

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:

• proposed retirement year;

• age;

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

• fuel efficiency;

• emissions rates of SO2, NOx

• types of installed control equipment or whether owners plan to install 

control equipment in the future;

, and carbon dioxide;

• 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.3

We also used regional day-ahead market prices from the 

IntercontinentalExchange (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 

 

1

Ventyx is an operating unit of the ABB Company. 

2

EIA is a statistical agency within the Department of Energy that collects, analyzes, and 

disseminates independent information on energy issues. 

3

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. 

Data Used
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 36 GAO-13-72 Electricity

each unit in our dataset.4 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.5

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.6 Of 

the total 959 units, 482 units belong to power companies that have 

announced plans for retiring at least one coal-fueled unit.

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.

 

4

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. 

5

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.

6

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. 

Results 
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 37 GAO-13-72 Electricity

We estimated the logit regression equation for the subgroup of 482 coalfueled 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 CoalFueled Unit Retirements–Dependent Variable Is the Probability of a Unit Retirement 

Announcement

Variable Coefficient Standard error Significance

Net summer capacity

a

-0.00198 0.0010 5.9%

Unit age 0.06647 0.0201 0.1%

SO2 emissions rate 0.68053 0.1550 0.0%

NOx emissions rate 3.64861 0.9168 0.0%

Regulatory status -1.56564 0.3331 0.0%

Constant -3.84944 1.3276 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.

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 
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 38 GAO-13-72 Electricity

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

Median value 

of variable

Value with 

10% change

Change in 

probability of 

retirement 

Net summer capacity (size of unit) 193 212 -2%

Age of unit 43 47 7%

Unit’s SO2 emissions rate 0.49 0.54 1%

Unit’s NOx emissions rate 0.20 0.22 2%

Source: GAO analysis of Ventyx data.

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

Median value 

of variable

Value with 

10% change

Change in 

probability of 

retirement 

Net summer capacity (size of unit) 230 253 -1%

Age of unit 43 47 4%

Unit’s SO2 emissions rate 0.57 0.63 1%

Unit’s NOx emissions rate 0.23 0.25 1%

Source: GAO analysis of Ventyx data.

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 
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 39 GAO-13-72 Electricity

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.7

The next step in our analysis was to use the resulting logit regression 

equation to estimate the number and generating capacity of other coalfueled 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.

 

7

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.

Analysis Indicates 

Units Power 

Companies Likely to 

Consider Retiring
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 40 GAO-13-72 Electricity

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

Units owned by 

companies that 

have announced at 

least one coalfueled unit 

retirement

Units owned by 

companies that 

have announced no

coal-fueled unit 

retirements 

Total coal-fueled 

units

All units 

Number 482 477 959 

Net summer 

capacity 158,000 MW 148,000 MW 306,000 MW

Units planned for retirement or that may be considered for retirement

Number 174 90 to 138 264 to 312

Net summer 

capacity 30,400 MW

15,700 to 25,200 

MW

46,100 to 55,600 

MW

Net summer 

capacity as percent 

of all units 19% 11 to 17% 15% to 18%

Generation

150 million MWh

91 to 151 million 

MWh

241 to 301 million 

MWh

Generation as a 

percent of all units 16% 10 to 16% 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.

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 
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 41 GAO-13-72 Electricity

and average annual generation of 241 to 301 million MWh.

8 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.

This section discusses the limitations of our model and alternative model 

specifications that we tested.

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.9

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 

Such differences could result in omitted variable 

bias.

 

8

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.

9

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.”

Limitations and 

Alternative Model 

Specifications 

Limitations 
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 42 GAO-13-72 Electricity

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.10

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.

Effectively, 

therefore, we assumed that power companies have very similar 

expectations regarding these factors.

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.

 

10To do so would have required an extensive survey of power companies, which was 

beyond the scope of our review. 

Alternative Specifications
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 43 GAO-13-72 Electricity

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

Variable Coefficient Standard error Significance

Net summer capacity

a

-0.00198 0.0014 14.9%

Unit age 0.06647 0.0269 1.3%

SO2 emissions rate 0.68053 0.2041 0.1%

NOx emissions rate 3.64861 1.1659 0.2%

Regulatory status -1.56564 0.3039 0.0%

Constant -3.84944 1.7726 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.

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.11

 

11State 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.

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 -
Appendix I: Analysis of Characteristics of 

Coal-Fueled Generating Units That Power 

Companies Plan to Retire

Page 44 GAO-13-72 Electricity

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 CoalFueled Unit Retirements Including Adjusted Marginal Cost and Interaction Term

Variable Coefficient Standard error Significance

Net summer capacity

a

-0.0019 0.0011 8.9%

Unit age 0.0667 0.0204 0.1%

SO2 emissions rate 0.8113 0.1763 0.0%

NOx emissions rate 3.4200 0.9328 0.0%

Adjusted marginal cost 5.8028 2.6250 2.7%

Cost and regulation interaction -8.1719 2.7112 0.3%

Regulatory status 3.1255 1.4965 3.7%

Constant -6.9313 2.0123 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.

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.
Appendix II: Description of Selected Scenarios 

and Forecasts

Page 45 GAO-13-72 Electricity

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

Scenario Description 

Average annual change 

in electricity produced

from coal, 2010-2035 

(percentage)

EIA Annual Energy Outlook

a

Reference 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. 0.1%

Low Coal Price 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. 0.5%

High Coal Price 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. -0.6%

Low Gas Price 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. -.7%

High Gas Price 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. 0.3%

$15 Greenhouse Gas Price 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. -3.5%

$25 Greenhouse Gas Price 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. -9.2%

Appendix II: Description of Selected 

Scenarios and Forecasts
Appendix II: Description of Selected Scenarios 

and Forecasts

Page 46 GAO-13-72 Electricity

Scenario Description 

Average annual change 

in electricity produced

from coal, 2010-2035 

(percentage)

High Economic Growth

a

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.

0.3%

High Use of Energy Efficient 

Technologies 

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.

-1.1%

IHS Global Insight

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 capand-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.

-0.5%

IEA World Energy Outlooka

Current policies A baseline scenario based on government policies and measures 

enacted by mid-2011. 

0.8%

New policies 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.

-0.1%

Scenario 3 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. 

-3.0%

Sources: EIA, IHS Global Insight, IEA.

a

IEA data reflect change from 2009 to 2035.
Appendix III: GAO Contact and Staff 

Acknowledgments

Page 47 GAO-13-72 Electricity

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

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.

Appendix III: GAO Contact and Staff 

Acknowledgments 

GAO Contact

Staff 

Acknowledgments
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