CRS Report for Congress

Prepared for Members and Committees of Congress 

Displacing Coal with Generation from 

Existing Natural Gas-Fired Power Plants 

Stan Mark Kaplan 

Specialist in Energy and Environmental Policy 

January 19, 2010 

Congressional Research Service

7-5700 

www.crs.gov 

R41027 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 

Summary 

Reducing carbon dioxide emissions from coal plants is a focus of many proposals for cutting 

greenhouse gas emissions. One option is to replace some coal power with natural gas generation, 

a relatively low carbon source of electricity, by increasing the power output from currently 

underutilized natural gas plants. 

This report provides an overview of the issues involved in displacing coal-fired generation with 

electricity from existing natural gas plants. This is a complex subject and the report does not seek 

to provide definitive answers. The report aims to highlight the key issues that Congress may want 

to consider in deciding whether to rely on, and encourage, displacement of coal-fired electricity 

with power from existing natural gas plants. 

The report finds that the potential for displacing coal by making greater use of existing gas-fired 

power plants depends on numerous factors. These include: 

• The amount of excess natural gas-fired generating capacity available. 

• The current operating patterns of coal and gas plants, and the amount of 

flexibility power system operators have for changing those patterns. 

• Whether or not the transmission grid can deliver power from existing gas power 

plants to loads currently served by coal plants. 

• Whether there is sufficient natural gas supply, and pipeline and gas storage 

capacity, to deliver large amounts of additional fuel to gas-fired power plants. 

There is also the question of the cost of a coal displacement by gas policy, and the impacts of 

such a policy on the economy, regions, and states. 

All of these factors have a time dimension. For example, while existing natural gas power plants 

may have sufficient excess capacity today to displace a material amount of coal generation, this 

could change in the future as load grows. Therefore a full analysis of the potential for gas 

displacement of coal must take into account future conditions, not just a snapshot of the current 

situation. 

As a step toward addressing these questions, Congress may consider chartering a rigorous study 

of the potential for displacing coal with power from existing gas-fired power plants. Such a study 

would require sophisticated computer modeling to simulate the operation of the power system to 

determine whether there is sufficient excess gas fired capacity, and the supporting transmission 

and other infrastructure, to displace a material volume of coal over the near term. Such a study 

could help Congress judge whether there is sufficient potential to further explore a policy of 

replacing coal generation with increased output from existing gas-fired plants. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 

Contents 

Introduction ................................................................................................................................1

Purpose and Organization......................................................................................................1

Issues Not Considered in the Report......................................................................................2

Background on Gas-Fired Generation and Capacity.....................................................................3

Capacity Trends ....................................................................................................................3

Factors Supporting the Boom in Gas-Fired Plant Construction ..............................................4

Technology .....................................................................................................................4

Natural Gas Prices ..........................................................................................................5

Carbon Dioxide Emissions ..............................................................................................6

Electric Power Industry Restructuring and Overbuilding .................................................6

Coal Displacement Feasibility Issues...........................................................................................9

Estimates of Displaceable Coal-Fired Generation and Emissions...........................................9

Transmission System Factors ..............................................................................................10

Isolation of the Interconnections....................................................................................12

Limited Long-Distance Transmission Capacity..............................................................12

Transmission System Congestion ..................................................................................13

Power Plant Proximity Analysis ....................................................................................14

System Dispatch Factors .....................................................................................................18

Natural Gas Supply and Price..............................................................................................19

Natural Gas Transportation and Storage...............................................................................22

Policy Considerations ...............................................................................................................23

Figures 

Figure 1. Net Change in Generating Capacity by Energy Source, 1990 to 2007............................3

Figure 2. Shares of Total Generating Capacity by Energy Source, 1989 and 2007 ........................4

Figure 3. Henry Hub Cash Spot Price for Natural Gas .................................................................6

Figure 4. Location of Large Coal-Fired Power Plants in the Conterminous States ...................... 11

Figure 5. Location of Large NGCC Power Plants in the Conterminous States ............................ 11

Figure 6. United States Power System Interconnections.............................................................12

Figure 7. Coal Plants with Hypothetical Generation Displaced by a NGCC Plant Within 

10 Miles.................................................................................................................................16

Figure 8. Coal Plants with Hypothetical Generation Displaced by a NGCC Plant Within 

25 Miles.................................................................................................................................16

Figure 9. Monthly Capacity Factors in 2007 for Study Group Coal and NGCC Plants................18

Figure 10. Hourly Coal and Combined Cycle Generation at Plant Barry ....................................19

Figure A-1. Elements of the Electric Power System...................................................................25

Figure A-2. Illustrative Daily Load Curve .................................................................................27

Figure B-1. Schematic of a Combined Cycle Power Plant..........................................................29
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

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Tables 

Table 1. Growth in Generating Capacity, 1990 - 2007..................................................................7

Table 2. Utilization of Study Group NGCC Plants, 2007..............................................................8

Table 3. Approximation of the Maximum Displaceable Coal-Fired Generation, Based on 

2007 Data ................................................................................................................................9

Table 4. Approximation of Maximum Displaceable CO2 Emitted by Coal-Fired 

Generators, Based on 2007 Data...............................................................................................9

Table 5. Hypothetical Estimates of the Displacement of Coal Generation and Emissions 

by Existing NGCC Plants Based on Proximity .......................................................................17

Table 6. Illustrative Estimates of Increased Natural Gas Demand For Coal Displacement 

Compared to Total National Demand......................................................................................20

Table 7. Illustrative Estimates of Increased Natural Gas Demand Relative to Electric 

Power Demand, Based on 2007 Data......................................................................................23

Appendixes 

Appendix A. Background on the Electric Power System............................................................25

Appendix B. Combined Cycle Technology ................................................................................29

Contacts 

Author Contact Information ......................................................................................................30
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

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Introduction 

Purpose and Organization 

Coal-fired power plants currently account for about 80% of CO2 emissions from the U.S. electric 

power industry and about 33% of all U.S. CO2 emissions.1 Accordingly, reducing CO2 emissions 

from coal plants is a focus of many proposals for cutting greenhouse gas emissions. Options 

include capturing and sequestering the CO2 emitted by coal plants, and/or replacing coal-fired

generation with low- and zero-carbon sources of electric power, such as wind or nuclear power. 

Another option is to replace coal power with increased use of natural gas generation. Natural gas 

is not a zero-carbon fuel, but gas-fired power using modern generating technology releases less 

than half of the CO2 per megawatt-hour (MWh) as a coal plant. Recent large increases in 

estimates of natural gas reserves and resources, especially from shale formations, have further fed 

interest in natural gas as a relatively low carbon energy option. 

One proposal is that the nation can and should achieve near-term reductions in carbon emissions 

by making more use of existing natural gas plants. This argument was made at an October 2009 

Senate Energy and Natural Resources Committee hearing on The Role of Natural Gas in 

Mitigating Climate Change. An executive for a large natural gas pipeline company stated that 

“Just as natural gas plays a key role in meeting U.S. energy demands, it can also play a key role 

in providing meaningful, immediate, and verifiable [CO2] emission reductions.” 2 [emphasis 

added] The witness for Calpine, a large operator of gas-fired power plants, stated that: 

I am here today to tell you that we could, today, simply through the increased use of existing 

natural-gas fired power plants, meaningfully reduce the CO2 emissions of the power sector, 

immediately and for the foreseeable future. In other words, a near- and medium-term 

solution to our climate change challenge is at hand. No guesswork. No huge spending 

programs needed. That power would be reliable—available all day, every day. And if we 

embrace this solution with the right incentives, American business would continue to invest 

its own capital in existing proven technologies to build even more natural gas fired plants to 

dramatically further reduce emissions for the longer term. [emphasis added]3

Both of these statements emphasize the claimed immediate carbon reductions that can result from 

increased use of natural gas. This would be accomplished by squeezing more electricity from 

existing gas-fired power plants, so that coal-fired plants can be operated less and CO2 emissions 

quickly and substantially reduced. 

1

 Energy Information Administration (EIA), Annual Energy Review 2008, Tables 12.1 and 12.7b, 

http://www.eia.doe.gov/emeu/aer/envir.html. 

2

 Written testimony of Dennis McConaghy, Executive Vice President, TransCanada Pipelines, Ltd., before the Senate 

Energy and Natural Resources Committee hearing on The Role of Natural Gas in Mitigating Climate Change, October 

28, 2009, p. 6, http://energy.senate.gov/public/index.cfm?FuseAction=Hearings.Hearing&Hearing_ID=788a1684-

b2a2-f5bb-f574-81b9257ba5aa. 

3

 Written testimony of Jack Fusco, President and CEO, Calpine Corp., before the Senate Energy and Natural Resources 

Committee hearing on The Role of Natural Gas in Mitigating Climate Change, October 28, 2009, p. 1, 

http://energy.senate.gov/public/index.cfm?FuseAction=Hearings.Hearing&Hearing_ID=788a1684-b2a2-f5bb-f574-

81b9257ba5aa. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 2 

This report provides an overview of the issues involved in displacing coal-fired generation with 

electricity from existing natural gas plants. This is a complex subject and the report does not seek 

to provide definitive answers. The report aims to highlight the key issues that Congress may 

consider in deciding whether to rely on, and encourage, displacement of coal-fired electricity with 

power from existing natural gas plants. 

The balance of the report is organized as follows: 

• Background on gas-fired generation and capacity. 

• Coal displacement feasibility issues. 

• Policy considerations. 

The report also includes two appendices. Appendix A, Background on the Electric Power 

System, may be of particular value to readers relatively new to the subject. Appendix B provides 

information on the gas-burning combined cycle generating technology discussed in the report. 

Issues Not Considered in the Report 

Several topics are beyond the scope of this report:

• What would be the cost of a policy of displacing coal with natural gas? The cost 

would depend on a host of uncertain variables, such as future natural gas and coal 

prices, any need to build additional pipeline and transmission line facilities, and 

the cost of carbon (if any). 

• Could natural gas be burned on a large scale in existing coal plants? Assessing 

this option would require engineering analysis of the plants and determining how 

many coal plants have access to high capacity natural gas pipelines. 

• How will circumstances change over time? For example, while existing natural 

gas plants may have enough excess capacity today to displace a material amount 

of coal generation, this could change in the future as load grows.

• What kind of existing natural gas plants could be used to displace coal? This 

report focuses on the potential for displacing coal generation with increased use 

of underutilized “combined cycle” generating plants, the most modern and 

efficient type of natural gas-fired power plants. Two other types of gas-fired 

plants have low utilization rates: peaking plants (stand-alone combustion turbines 

and diesel generators) and old steam-electric natural gas plants. These are not 

reviewed in the report because they are relatively inefficient and may not be 

designed or permitted for baseload operation. 

Addressing these issues would require computer modeling and engineering analysis beyond the 

scope of this report. As noted in the concluding section of the report, these issues, if of interest to 

Congress, could be part of a more comprehensive review of the potential for displacing coal with 

natural gas. 
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Background on Gas-Fired Generation and Capacity 

The argument for displacing coal with natural gas rests on the fact that the United States has a 

large base of advanced technology, underutilized, gas-burning power plants. This section of the 

report describes how this reservoir of underutilized natural gas combined cycle (NGCC) plants 

came about, and why it may represent an option for reducing the use of coal plants. 

Capacity Trends 

From the 1990s into this century, gas-fired power plants have constituted the vast majority of new 

generating capacity built in the United States. This development is illustrated by Figure 1 for the 

period 1990 to 2007. Minimal new coal capacity was constructed and the growth in nuclear 

capacity was limited to uprates to existing plants. Only wind capacity has challenged the preeminence of natural gas as the source of new generating capacity, and then only in the latter part 

of the 2000s when total capacity additions declined sharply. 

Figure 1. Net Change in Generating Capacity by Energy Source, 1990 to 2007 

Net Summer Capacity 

-10,000,000

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Kilowatts of Generating Capacity

Natural Gas

Coal

Nuclear

Hydroelectric

Wind

All Other

Source: Calculated from data in EIA, Annual Energy Review 2008, Table 8.11a, http://www.eia.doe.gov/emeu/aer/

elect.html. 

Notes: Capacity can decrease when retirements and deratings of units exceed capacity additions and increases. 

Also, in some cases the primary fuel of a unit may change, such as from wood to coal. The net change is 

calculated as the year over year change for each type of capacity. 

As shown in Figure 2, this building boom doubled the natural gas share of total generating 

capacity between 1989 and 2007. Natural gas-fired capacity is now the largest component of the 

national generating fleet. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 4 

Figure 2. Shares of Total Generating Capacity by Energy Source, 1989 and 2007 

Shares of Total Net Summer Capacity 

19%

39%

42%

31%

14%

10%

10%

8%

15% 11%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1989 2007

% of Total Generating Capacity

All Other

Hydroelectric

Nuclear

Coal

Natural Gas

Source: Calculated from data in EIA, Annual Energy Review 2008, Table 8.11a, http://www.eia.doe.gov/emeu/aer/

elect.html. 

Although natural gas is the largest source of generating capacity, it trails far behind coal as a 

source of actual electricity generation.4 In 2008, coal accounted for 49% of all electricity 

produced, compared to 21% for natural gas, 20% for nuclear power, and 6% for hydroelectric 

generation.5

 The remainder of this section will explain why so much new gas-fired generation 

was built and why it is underutilized. 

Factors Supporting the Boom in Gas-Fired Plant Construction 

Natural gas was the major source of new capacity in the 1990s and early 2000s in part by default. 

Nuclear and coal power have been burdened with cost, environmental, and (in the case of nuclear 

power) safety concerns. Oil-fired generation was essentially ruled out by the costs and supply 

risks of petroleum supplies. This left natural gas as the energy source for new non-renewable 

power plants. But in addition to the negatives that surrounded alternatives, gas fired capacity also 

grew because of favorable technological, cost, environmental, and power market characteristics. 

Technology 

The new gas-fired plants constructed in the 1990s and subsequently were built around the latest 

design of combustion turbines—a specialized form of the same kind of technology used in a jet 

engine, but mounted on the ground and used to rotate a generator. Stand-alone combustion 

turbines were built to serve as peaking units that would operate only a few hundred hours a year. 

However, the most important technological development was the application of combustion 

4

 “Capacity” is a measure of the potential instantaneous electricity output from a power plant, usually measured in 

megawatts or kilowatts. “Generation” is the actual amount of electricity produced by the plant over a period of time, 

usually measured in megawatt-hours or kilowatt-hours. For additional information see Appendix A.

5

 These four sources accounted for 96% of electricity production in 2008, which is the typical combined share going 

back to the 1980s. All other sources, such as wind, petroleum, and biomass, account for the remaining 4%. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

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turbines in modern natural gas combined cycle power plants. (For additional information see 

Appendix B.) These plants were often intended to serve as baseload generators which would 

operate 70% or more of the time. The NGCC has three important characteristics: 

• The technology is very efficient, because it makes maximum use of the energy 

in the fuel through a two-step generating process that captures waste heat that 

would otherwise be lost.6

• NGCC plants can be built relatively quickly and cheaply. An NGCC plant 

costs roughly $1,200 per kilowatt of capacity, about half as much as for a coalfired plant, and can be built in about two to three years from ground-breaking to 

operation. This compares to about to five to six years to build a coal plant. Coal 

plants also tend to have longer pre-construction planning and permitting phases.7

• Combined cycle technology is suitable for relatively small scale and modular 

construction. NGCC plants can be economically built at unit sizes of about 100 

MW, and larger projects can be constructed by adding units in a building block 

fashion over time. Coal plants in contrast are generally economical only at a unit 

size of several hundred megawatts. 

For the reasons discussed below, these characteristics made the NGCC an attractive technology 

option for the independent power producers that dominated the construction of new power plants 

in the 1990s and after. 

Natural Gas Prices 

The construction of new gas-fired capacity was also encouraged by relatively low natural gas 

prices in the 1990s. As illustrated by Figure 3, the spot price for natural gas hovered around 

$2.00 to $3.00 per MMBtu (nominal dollars) through the decade, and a widely held expectation 

was that gas prices would remain low into the future.

8

6

 By extracting the maximum energy from fuel combustion, modern combined cycles can reportedly achieve heat rates 

in the range of 6,752 to 6,333 btus per kwh. This compares to 9,200 to 8,740 btus per kwh for steam electric coal 

technology. (EIA, Assumptions to the Annual Energy Outlook 2009, Table 8.2, http://www.eia.doe.gov/oiaf/aeo/

assumption/index.html.) This efficiency advantage can make combined cycles very economical to operate. 

7

 For more information on power plant cost and construction issues, see CRS Report RL34746, Power Plants: 

Characteristics and Costs, by Stan Mark Kaplan. 

8

 Rebecca Smith, “Utilities Question Natural-Gas Forecasting,” The Wall Street Journal, December 27, 2004. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

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Figure 3. Henry Hub Cash Spot Price for Natural Gas 

November 1993 to December 2009, Nominal Dollars 

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

Nov-93Nov-94Nov-95Nov-96Nov-97Nov-98Nov-99Nov-00Nov-01Nov-02Nov-03Nov-04Nov-05Nov-06Nov-07Nov-08Nov-09

$ per MMBtu

Henry Hub Cash Spot Price

Source: U.S. Federal Reserve Bank of St. Louis FRED database (http://research.stlouisfed.org/fred2/series/

GASPRICE?cid=98). 

Carbon Dioxide Emissions 

The operation of NGCC plants, and natural gas plants generally, produce fewer harmful 

environmental impacts than coal-fired plants, and have been much easier to site and permit than 

coal plants. NGCC technology has fewer air emissions than coal plants in part because of the 

nature of the fuel, and in part because of the greater efficiency of the technology. For example, 

natural gas when burned inherently emits about half as much carbon dioxide as coal.9

 However, 

because combined cycle plants are more efficient than typical existing coal plants in converting 

fuel into electricity, the difference in emissions is greater when measured in terms of CO2

released per megawatt-hour of electricity produced. By this measure a modern combined cycle 

emits only about 40% of the CO2 per MWh as a typical existing coal plant.10

Electric Power Industry Restructuring and Overbuilding

Restructuring of the electric power industry (beginning in the late 1970s and accelerating in the 

1990s) included federal and state policies that encouraged the separation of power generation and 

9

 Natural gas emits 117.08 pounds CO2 per MMBtu burned. The comparable numbers for subbituminous, bituminous, 

and lignite coal are, respectively, 212.7, 205.3, and 215.4 pounds of CO2 per MMBtu burned. EIA, Electric Power 

Annual 2007, Table A3, http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html. 

10 Other environmental advantages of combined cycle plants include minimal or zero emissions of sulfur dioxides and 

mercury; no solid wastes, such as ash and scrubber sludge; no coal piles with attendant fugitive dust and runoff 

problems; and the fuel is delivered by pipeline rather than railroad or truck. A combustion turbine burning natural gas 

will emit more nitrogen oxides (NOx) per MMBtu of fuel consumed than a coal-fired boiler, and depending on the 

location of a gas-fired plant it may have to install a low NOx combustion system and a selective catalytic reduction 

system to capture NOx emissions. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 7 

power plant construction from other utility functions. In the 1990s, new independent power 

producers (IPPs) bought power plants from utilities and constructed most of the new generating 

capacity. Because these companies sold power into competitive markets and did not have the 

security of regulated rates and guaranteed markets, they generally sought to minimize risks by 

constructing relatively low cost, quick-to-build, power plants. 

For these reasons, independent power producers built many NGCC plants, largely to meet 

baseload demand. As shown in Table 1, between 1990 and 2007 over 168,000 MW of NGCC 

capacity was built at 345 plant sites. This was an enormous building program, equivalent to 

adding 23% to the entire national generating fleet that existed in 1990. However, the growth in 

generating capacity did not stop with new combined cycle plants. As also shown in Table 1,

another 89,843 MW of less efficient stand-alone peaking turbines were constructed, plus another 

56,939 MW of other generating technologies. When all of this capacity is added together, 

generating capacity grew by 43% between 1990 and 2007. 

Table 1. Growth in Generating Capacity, 1990 - 2007 

Natural Gas 

Combined Cycle 

(NGCC) 

Stand-Alone 

Combustion 

Turbine 

(Natural Gas) 

All Other Fuel 

Sources and 

Technologies Total 

Additions to 

Generating 

Capacity, 1990 – 

2007 (MW) 

168,259 89,843 56,939 315,041 

Additions as a 

Percent of Total 

1990 Generating 

Capacity (734,100 

MW) 

23% 12% 8% 43% 

Source: Calculated from the EIA-860 data file for 2007, http://www.eia.doe.gov/cneaf/electricity/page/

eia860.html. 

Notes: The capacity shown is net summer capacity. The All Other category contains 2,184 MW of gas-fired 

capacity, primarily in new internal combustion engines and steam turbines, and 5,432 MW of combined cycle and 

stand-alone combustion turbine capacity burning fuels other than natural gas (primarily stand-alone combustion 

turbines using distillate fuel oil).

By the mid-2000s it was apparent that the combined cycle building boom had resulted in excess 

and underutilized generating capacity. Too many plants were built, in part because of questionable 

investment decisions by independent developers operating in an immature restructured power 

market. The capacity glut was compounded by a dramatic increase in gas prices after 2000. (See 

Figure 3.) Even the high efficiency of the combined cycle plants could not compensate for gas 

prices that at times peaked above $10.00 per MMBtu, compared to $2.00 to $3.00 per MMBtu 

prices (nominal dollars) in the 1990s. 

The consequence of the combined cycle building boom and bust is that the fleet of NGCC plants 

has a large amount of unused generating capacity, as illustrated in Table 2 for a “study group” of 

large combined cycle plants defined for this report.11 Baseload operation can be reasonably 

11 The study group of combined cycle plants consists of plants with the following characteristics: minimum net summer 

(continued...) 
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defined as operation at an annual capacity factor of 70% or greater. As shown in Table 2, only 

13% of combined cycle capacity in the study group operated in this range in 2007. A third of the 

combined cycle capacity had a utilization rate of less than 30%; that is, the plants were the 

equivalent of idle more than 70% of the time. 

Table 2. Utilization of Study Group NGCC Plants, 2007 

Capacity Factor 

Category 

Net Summer 

Megawatts 

Percent of Total 

NGCC Megawatts 

Number of NGCC 

Plants 

Percent of Total 

NGCC Plants 

70% and Greater 22,151 13% 42 13% 

Under 70% to 50% 40,103 24% 68 22% 

Under 50% to 30% 50,711 30% 90 29% 

Under 30% 57,662 34% 114 36% 

Total 170,627 100% 314 100% 

Source: Calculated from the EIA-860 and EIA-906/920 databases for 2007 (http://www.eia.doe.gov/cneaf/

electricity/page/data.html). 

Notes: Detail many not add to total due to rounding. For information on the characteristics of the power plants 

selected for the study group, see footnote 11. 

In 2007 the study group of NGCC plants had an average capacity factor of 42%.12 In contrast, the 

study group of coal plants had an average capacity factor of 75%.13 It is this mismatch between 

combined cycle and coal plant operating patterns—the former, low carbon emitting but 

underutilized; the latter, high carbon emitting and highly utilized—that creates the interest and 

perceived opportunity for displacing coal power with gas generation from existing plants. 

(...continued) 

capacity of 100 MW; the plant operated at some point in time during 2007 and was in operational condition at the end 

of 2007; the plant’s primary fuel was natural gas; and the plant’s primary purpose was to sell power to the public. (This 

last criterion excludes industrial and commercial cogenerators who operate a power plant primarily to provide 

electricity and steam to a single business establishment.) A total of 314 combined cycle plants with total capacity of 

170,627 MW met these criteria. The study group of coal plants had the same criteria except that the capacity floor was 

250 MW and the primary fuel had to be coal or waste coal. A total of 298 coal plants with total capacity of 284,646 

MW met these criteria. CRS identified the plants and extracted the data from the EIA-860 and EIA-906/920 databases 

for 2007 (http://www.eia.doe.gov/cneaf/electricity/page/data.html). The 2007 generation from the plants in the 

combined cycle study group (630.4 million MWh) accounted for 98% of all gas-fired combined cycle generation in the 

electric power sector in 2007. Similarly, the generation from the coal plants in the study group (1,870.6 million MWh) 

accounted for 95% of all coal-fired generation in the electric power sector. 

12 Capacity factor is a measure of the actual utilization of a power plant compared to its hypothetical maximum 

utilization. For additional information see Appendix A.

13 For information on the study group of coal plants see footnote 11. Capacity factors were calculated using the EIA906/920 generation and EIA-860 generating capacity databases (http://www.eia.doe.gov/cneaf/electricity/page/

data.html). 
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Coal Displacement Feasibility Issues 

Estimates of Displaceable Coal-Fired Generation and Emissions 

The maximum coal-fired generation and emissions that may be displaceable by existing NGCC 

plants is estimated in Table 3 and Table 4. As noted above, the plants in the NGCC study group 

had an average capacity factor of 42% in 2007. As shown in the tables, if the utilization of this 

capacity could be essentially doubled to 85%, it would generate additional power equivalent to 

32% of all coal-fired generation in 2007, and could displace about 19% of the CO2 emissions 

associated with coal-fired generation of electricity. 

Table 3. Approximation of the Maximum Displaceable Coal-Fired Generation, Based 

on 2007 Data 

 (1) (2) (3) (4) (5) 

Actual NGCC 

Generation, 2007 

(MWh) 

Hypothetical NGCC 

Generation at an 

85% Capacity Factor 

(MWh) 

Hypothetical Surplus 

Generation Available 

for Coal 

Displacement 

(MWh) 

(2) – (1) 

Actual Coal-Fired 

Generation in 2007 

(MWh) 

Hypothetical Surplus 

NGCC Generation 

as a Percentage of 

Coal Generation 

(3) / (4) 

630,358,373 1,270,487,153 640,128,780 2,016,456,000 32% 

Source: CRS estimates based on EIA-906/920 and EIA-860 electric power databases, and EIA, Electric Power 

Annual 2007, Table ES1, http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html. 

Notes: The generation in column 1 is for the 314 NGCC plants included in the study group defined for this 

report. For additional information see footnote 11. As discussed in the main body of the report, several factors, 

such as transmission system limitations, will tend to drive actual displacement below the maximum potential. 

Also, this estimate is for 2007, and in other years the amount of surplus gas generation and the amount of coal 

generation will likely vary from 2007 values. 

Table 4. Approximation of Maximum Displaceable CO2 Emitted by Coal-Fired 

Generators, Based on 2007 Data 

 (1) (2) (3) (4) (5) (6) 

Estimated 

Hypothetical 

Coal 

Generation 

Displaced by 

Natural Gas 

(MWh) 

Estimated CO2 

Emissions from 

Displaced Coal 

Generation 

(Million Metric 

Tons) 

Estimated CO2

Emissions From 

NGCC 

Generation Used 

to Displace Coal 

(Million Metric 

Tons) 

Net Reduction in 

Emissions of 

CO2 by Natural 

Gas 

Displacement of 

Coal 

(Million Metric 

Tons) 

(2) – (3) 

Total CO2

Emissions from 

Coal for Power 

Generation, 

2007 

(Million Metric 

Tons) 

Hypothetical 

Net Reduction in 

CO2 Emissions 

as a Percentage 

of 2007 Total 

Electric Power 

Coal Emissions 

of CO2

(4) / (5) 

640,128,780a 635.7b 253.6c 382.1 2,002.4 19% 

Source: CRS estimates based on: EIA-906/920 database (http://www.eia.doe.gov/cneaf/electricity/page/

eia906_920.html); EIA, Electric Power Annual 2007, Table A3, http://www.eia.doe.gov/cneaf/electricity/epa/

epa_sum.html; EIA, Annual Energy Review 2008, Table 12.7a, http://www.eia.doe.gov/emeu/aer/envir.html. 
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Notes: As discussed in the main body of the report, several factors, such as transmission system limitations, will 

tend to drive actual displacement below the maximum potential. Also, this estimate is for 2007, and in other

years the amount of surplus gas generation and the amount of coal generation will likely vary from 2007 values. 

a. From Table 3, column 3. 

b. In 2007, total coal generation was 2,016,456,000 MWh (Table 3, column 4) and total CO2 emissions from 

coal were 2,002.35 million metric tons. This equates to 0.993 metric tons of CO2 per MWh of coal generation 

(the comparable value for a modern NGCC plant is about 0.4 metric tons of CO2 per MWh). Therefore, the 

estimated CO2 emissions from the displaced coal is 640,128,780 MWh x 0.993005 metric tons of CO2 per MWh 

= 635.651 million metric tons of CO2. 

c. Actual study group NGCC generation in 2007 was 630,358 MWh (Table 3, column 1). This generation 

consumed 4,702,226,931 MMBtus of natural gas, or 7.4596 MMBtus of gas per MWh. At this average heat rate, 

it would take 4,775,104,647 MMBtus of gas to displace 640,128,780 MWh of coal generation. This much gas 

burn would release 253.6 million metric tons of CO2, using an emissions factor of 117.08 pounds of CO2 per 

MMBtu of natural gas consumed and 2,204.6 pounds per metric ton. 

Although these calculations suggest that at most about a third of current (2007) coal-fired 

generation could be displaced by existing NGCC plants, it is unlikely that this maximum could 

actually be achieved. This section of the report will discuss issues that relate to the feasibility of

actually displacing coal with gas from existing power plants. The issues are: 

• Transmission system factors; 

• System dispatch factors; 

• Natural gas supply and price; and 

• Natural gas transportation and storage. 

Transmission System Factors 

If an NGCC generating unit is located at the same plant site as a coal-fired generating unit, it is 

probably fair to assume that the NGCC unit can use the same transmission lines as the coal unit 

and can transmit its power to any load the coal unit is used to meet. However, in most cases coal 

units and NGCC units are built at separate locations and rely on different transmission paths to 

move their power. This means that there is no guarantee that the NGCC plant can send its power 

to the same loads as the coal plant and by doing so displace coal-fired generation. 

Even on a regional level, coal and NGCC plants are not necessarily located in the same areas. 

The maps in Figure 4 and Figure 5 show, respectively, the location of large coal and NGCC 

plants in the conterminous states. The maps show that in some cases coal and NGCC plants are 

in the same regions, such as east Texas. On the other hand, California has many NGCC plants 

and no coal plants, while the Ohio River valley has a dense concentration of coal plants and only 

a handful of NGCC plants. 

This section of the report will discuss three types of transmission system constraints that can 

prevent one power plant from meeting the load currently served by another plant. These limits on 

the “transmission interchangeability” of coal and NGCC plants are: 

• Isolation of the Interconnections; 

• Limited long-distance transmission capacity; and 

• Transmission system congestion. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 11 

The concluding part of this section presents an analysis of potential coal displacement by gas 

using the proximity of coal and existing NGCC plants as a proxy for transmission 

interchangeability. 

Figure 4. Location of Large Coal-Fired Power Plants in the Conterminous States 

250 Megawatt and Greater Net Summer Capacity 

Source: Platts Powermap (fourth quarter 2009 database). 

Figure 5. Location of Large NGCC Power Plants in the Conterminous States 

100 Megawatt and Greater Net Summer Capacity 

Source: Platts Powermap (fourth quarter 2009 database). 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 12 

Isolation of the Interconnections 

The electric power grid covering the conterminous states is divided into three “interconnections,” 

Eastern, Western, and the ERCOT Interconnection that covers most of Texas (Figure 6). These 

three interconnections operate in most respects as independent systems. There are only a handful 

of limited, low capacity links between the interconnections. Consequently, surplus capacity in 

one interconnection cannot be used to meet load in another interconnection. 

Figure 6. United States Power System Interconnections 

Source: adapted from a map located on the Energy Information Administration website at 

http://www.eia.doe.gov/cneaf/electricity/page/fact_sheets/transmission.html. 

Notes: ERCOT = Electric Reliability Council of Texas. 

To illustrate with a hypothetical example, assume 1,000 MW of surplus NGCC capacity in the 

northern part of the ERCOT Interconnection, and a desired use for that capacity to displace coal 

in Oklahoma, which is in the Eastern Interconnection. Although the regions are adjacent, from 

the standpoint of the power grid they are electrically isolated from each other because, with very 

limited exceptions, the ERCOT and Eastern Interconnections are not linked. Therefore the 

displacement cannot take place. 

Limited Long-Distance Transmission Capacity 

Within each interconnection the network of power lines, generating plants, and electricity 

consumers are linked together. The grid operates in some respects like a single giant machine in 

which, for example, a disturbance in the operation of the transmission system in Maine is 

detectible by system monitors in Florida. 

Although all generators and loads within an interconnection are linked by the grid, the power grid 

is not designed to move large amounts of power long distances. The grid was not built in 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 13 

accordance with a “master plan,” analogous to the Interstate Highway System. Transmission 

lines were first built in the early 20th century by single utilities to move electricity to population 

centers from nearby power plants. As generation and transmission technology advanced, the 

distances between power plants and loads increased, but the model of a single entity building 

lines within its service territory to supply its own load still predominated. 

Over time the local grids began to interconnect, due to utilities building jointly owned power 

plants and because power companies began to grasp the economic and reliability benefits of being 

able to exchange power. Nonetheless, this pattern of development did not emphasize the 

construction of very long-distance inter-regional lines. Consequently, the capacity to move power 

long distances within interconnections is limited. For example, while a generator in Maine and a 

load in Florida are connected by the grid, it is not feasible to send power from Maine to Florida 

because the transmission lines do not have enough capacity to move the electricity. 

Additionally, over distances of hundreds of miles, losses occur with transmission of electricity, 

making the transfer uneconomic.14 Power can be moved long distances most efficiently by the 

highest voltage transmission lines, but only a small portion of the national grid consists of these 

types of lines.15 Much of the debate over the proposed increased use of renewable power 

involves how to build and pay for the new transmission lines that would be needed to move wind 

and solar power from remote locations to population centers, in part to displace fossil-fueled 

power plants. Coal displacement by existing gas-fired generators is a similar type of problem. If 

the existing transmission network does not have sufficient capacity in the right places, then it may 

not be practical to move gas-powered electricity to loads currently served by coal plants without 

investing in upgraded or new power lines. 

Transmission System Congestion 

Even across relatively short distances, options for moving power can be restricted by transmission 

line congestion. Transmission congestion occurs when use of a power line is limited to prevent 

overloading that can lead to failure of the line. Congestion can occur throughout a power system: 

• Regional congestion: for example, power flows are limited between the eastern 

and western parts of the PJM power pool (covering much of the Midwest and 

14 Line loss is the loss of electrical energy due to the resistance of the length of wire in a circuit. Much of the loss is 

thermal in nature. (This definition is a composite created from the glossaries at http://www.eia.doe.gov/glossary/

glossary_l.htm and http://www.ewh.ieee.org/sb/srisairamec/glossary/k-lglos.htm.) 

15 Most of the transmission grid uses alternating current (AC) technology which is prone to line losses. By using 

transmission lines with higher kilovolt (kV) ratings, more power can be transported long distances with fewer losses. 

The highest capacity AC lines currently in use in the United States have a rating of 765 kV, but according to DOE these 

lines make up less than 2% of the grid. An alternative, direct current (DC) technology, can move large amounts of 

power long distances with minimal losses. However, DC lines are in only limited use (about 2% of the grid) because 

they are more difficult and expensive to integrate into the grid than AC lines. Proposals have been made to upgrade the 

AC network by building more 765 kV lines and lines using even high capacity AC technology (referred to as ultra high 

voltage transmission), and to build more DC lines. These proposals are generally focused on moving renewable power 

long distances. For example, see American Electric Power, Interstate Transmission Vision for Wind Integration,

undated, http://www.aep.com/about/i765project/docs/WindTransmissionVisionWhitePaper.pdf, and the Joint 

Coordinated System Plan proposal at http://www.jcspstudy.org/. (The transmission line statistics cited in this footnote 

are from DOE, National Transmission Grid Study, May 2002, p. 3, http://www.ferc.gov/industries/electric/indus-act/

transmission-grid.pdf.) 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 14 

middle Atlantic regions) by congestion.16 In the western states, examples of 

congested links include power flows between Montana and the Pacific 

Northwest, and between Utah and Nevada.17

• State-level congestion: for example, congestion restricts power flows into and out 

of southwestern Connecticut.18

• Local congestion: These are “load pockets” with limited ability to import power. 

New York City is an example of a load pocket. 

Transmission congestion can increase costs to consumers by forcing utilities to depend on nearby 

inefficient power plants to meet load instead of importing power from more distant but less costly 

units. Studies suggest that the annual costs of transmission congestion range from the hundreds of 

millions to billions of dollars.19 However, for the purposes of this report the key aspect of 

transmission system congestion is not the cost impact, but the restrictions it imposes on power 

flows. Because of congestion, it may not be possible to ship power from an underutilized NGCC 

plant to a load served by coal power, because the transmission path available to the combined 

cycle is too congested to carry the electricity. 

The solution for congestion is not necessarily massive transmission construction. For example, 

DOE found that in the Eastern Interconnection “a relatively small portion of constrained 

transmission capacity causes the bulk of the congestion cost that is passed through to consumers. 

This means that a relatively small number of selective additions to transmission capacity could 

lead to major economic benefits for many consumers.”20 However, in the absence of this 

construction, congestion remains a constraint on the choice of power plants available to meet a 

load. 

Power Plant Proximity Analysis 

Transmission system limitations on coal displacement can be rigorously analyzed using 

sophisticated computer models. Such an analysis is beyond the scope of this report. However, a 

first approach to the significance of transmission factors can be made by examining how close 

coal plants are to existing NGCC plants. The assumption behind such a “proximity analysis” is 

that the closer an NGCC plant is to a coal plant, the more likely that the NGCC plant will connect 

to the same transmission lines as the coal plant. If the NGCC plant has this comparable 

transmission access—that is, the combined cycle is “transmission interchangeable” with the coal 

plant—it potentially could serve the same load as the coal plant and supplant the coal generation. 

16 Ventyx Corp., Major Transmission Constraints in PJM, 2007, http://www1.ventyx.com/pdf/wp07-transmissionconstraints.pdf. 

17 Western Electric Coordinating Council, 2008 Annual Report of the Transmission Expansion Planning Policy 

Committee, Executive Summary, March 31, 2009, p.9, http://www.wecc.biz/committees/BOD/TEPPC/

Shared%20Documents/TEPPC%20Annual%20Reports/2008/CoverLetter_Exec_Summary_Final_.pdf. 

18 Connecticut General Assembly, Office of Legislative Research, Factors Behind Connecticut’s High Electric Rates,

August 5, 2008, No. 2008-R-0452, http://www.cga.ct.gov/2008/rpt/2008-R-0452.htm. 

19 Bernard Lesieutre and Joseph Eto, Electricity Transmission Congestion Costs: A Review of Recent Reports,

Lawrence Berkeley National Laboratory, p. 2, http://certs.lbl.gov/pdf/54049.pdf, and U.S. Department of Energy, 

National Transmission Grid Study, May 2002, pp. 16–18, http://www.pi.energy.gov/documents/TransmissionGrid.pdf. 

20 U.S. DOE, National Electric Transmission Congestion Study, August 2008, p. 28, http://www.pi.energy.gov/

documents/TransmissionGrid.pdf. Emphasis in the original not shown. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 15 

CRS performed a proximity analysis for the coal plants and NGCC plants in the study groups 

defined for this report. The analysis was conducted as follows, in all cases using 2007 data (the 

most recent pre-recession year for which complete data were available): 

(1) Study groups of large coal plants and NGCC plants were defined. The plants in these 

groups accounted for the great majority of power plant coal generation and NGCC 

generation in 2007.21

(2) The latitude and longitude of each plant (provided by EIA) was entered into a 

geographical information system (GIS). 

(3) The GIS was used to identify all coal plants with one or more existing NGCC plants 

within a ten mile radius. The hypothetical surplus generation for each NGCC plant 

within the ten-mile radius was calculated and assumed to displace generation from 

the coal plant.22 If one NGCC plant was within ten miles of two or more coal plants, 

it was allocated first to the coal plant with the largest estimated CO2 emissions in 

2007.23

(4) A second version of Step 3 was performed which included all NGCC plants within 25 

miles of a coal plant. 

The maps in Figure 7 and Figure 8 show the locations of the coal plants assumed to have 

generation displaced by existing NGCC plants.24

21 The study group of combined cycle plants includes 314 larger plants that accounted for 98% of combined cycle 

generation in the electric power sector in 2007. The study group of coal plants includes 298 larger plants that accounted 

for 95% of coal-fired generation in the electric power sector in 2007. For additional information on the characteristics 

of the study groups see footnote 11. 

22 Actual generation in 2007 is from the EIA-906/920 database. Capacity factors were computed using this generation 

data and each plant’s capacity as reported in the EIA-860 database. An NGCC plant was assumed to have surplus 

generation if its annual capacity factor in 2007 was less than 85%; that is, the hypothetical surplus generation available 

to displace coal was the difference between the NGCC plant’s actual generation in 2007 and the electricity it could 

have produced at an 85% utilization rate. A few NGCC plants had capacity factors of 85% or greater in 2007 and were 

therefore assumed to have no surplus generation available for coal displacement. The EIA databases are available at 

http://www.eia.doe.gov/cneaf/electricity/page/data.html. 

23 CO2 emissions were estimated for each coal plant based on the type and volume of coal consumed. Fuel consumption 

in MMBtus was taken from the EIA-906/920 database and used to calculate CO2 emissions using the emission factors 

in EIA, Electric Power Annual 2007, Table A3, http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html. The same 

data sources were used to calculate CO2 emissions for combined cycles. 

24 The maps only show coal plants assumed to have had generation displaced, and the existing NGCC plants 

responsible for the displacement. If a coal plant had an NGCC plant with the ten or 25 mile radius, but the NGCC plant 

was assumed to be unavailable to displace coal (for example, because it had a capacity factor in 2007 of 85% or higher) 

no coal is assumed to have been displaced and the coal plant is not shown on the map. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 16 

Figure 7. Coal Plants with Hypothetical Generation Displaced by a NGCC Plant 

Within 10 Miles 

Source: CRS estimates, mapped using the Platts Powermap system.

Notes: The maps only show coal plants assumed to have had generation displaced. If a coal plant has an NGCC 

plant with the ten mile radius, but the NGCC plant was assumed to be unavailable to displace coal (for example, 

because it had a capacity factor in 2007 of 85% or higher) the coal plant is not shown on the map. 

Figure 8. Coal Plants with Hypothetical Generation Displaced by a NGCC Plant 

Within 25 Miles 

Source: CRS estimates, mapped using the Platts Powermap system.

Notes: The maps only show coal plants assumed to have had generation displaced. If a coal plant has an NGCC 

plant with the 25 mile radius, but the NGCC plant was assumed to be unavailable to displace coal (for example, 

because it had a capacity factor in 2007 of 85% or higher) the coal plant is not shown on the map. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 17 

This analysis is not a forecast. It is a first approach to estimating coal displacement potential 

based on one factor, the proximity of coal and existing NGCC plants. Many other factors, 

including, for example, how utility systems are dispatched, the configuration and capacity of the 

electric power transmission system, fuel cost and availability, natural gas transportation capacity, 

and power system reliability requirements, would influence actual coal displacement potential. 

These other factors could increase or decrease the potential displacement. 

Table 5, which gives the results of the proximity analysis, shows in column 4 that existing NGCC 

plants located near coal plants might be able to achieve 15% to 28% of the potential maximum 

coal generation and CO2 emissions displacement. However, the displaceable coal generation and 

emissions (see Table 3 and Table 4) are only a fraction of total U.S. coal generation and CO2. As 

shown in Table 5, column 5, the hypothetical displaced coal generation and emissions are 

equivalent to 5% to 9% of total U.S. coal generation, and 3% to 5% of the associated CO2

emissions. 

Given its limitations, the analysis suggests that existing NGCC plants near coal plants may be 

able to account for something on the order of 30% or less of the displaceable coal-fired 

generation and CO2 emissions. Greater displacement of coal by existing NGCC plants would 

depend on more distant NGCC plants which would be less clearly “transmission interchangeable” 

with coal plants. This emphasizes the importance that the configuration and capacity of the 

transmission system will likely play in determining the actual potential for displacing coal with 

power from existing NGCC plants. 

Table 5. Hypothetical Estimates of the Displacement of Coal Generation and 

Emissions by Existing NGCC Plants Based on Proximity 

Based on 2007 Data 

Case 

(1) 

Category 

(2) 

Amount 

Displaced 

(3) 

Amount Displaced 

as a % of the 

Maximum Potential 

Displacement of 

Coal by Existing 

NGCC Plantsa

(4) 

Amount 

Displaced as a % 

of Total Electric 

Power Sector 

Coal MWh and 

Associated CO2 

EmissionsError! 

Reference source not found.

(5) 

Generation and Generation 101.8 Million MWh 16% 5% 

CO2 Displaced for 

Coal Plants within 

10 Miles of a 

NGCC PlantError! 

Reference source not 

found.

CO2 Emissions 58.1 Million Metric 

Tons 15% 3% 

Generation and Generation 181.5 Million MWh 28% 9% 

CO2 Displaced for 

Coal Plants within 

25 Miles of a 

NGCC PlantError! 

Reference source not 

found.

CO2 Emissions 104.8 Million Metric 

Tons 27% 5% 

Source: CRS estimates primarily based on EIA data. See the main text of the report for more information. For 

detailed backup, such as lists of plants, contact the author. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 18 

Notes: This is not a forecast; it is a rough approximation of coal displacement potential based on one factor, the 

proximity of coal and existing NGCC plants. Many other factors, including, for example, how utility systems are 

dispatched, the configuration and capacity of the electric power transmission system, fuel cost and availability, 

natural gas transportation capacity, and power system reliability requirements, would influence actual coal 

displacement potential. These other factors could increase or decrease the potential displacement. MWh = 

Megawatt-hours; NGCC = natural gas combined cycle. 

a. The values in this column are calculated using column 3; Table 3, column 3; and Table 4, column 4. 

b. The values in this column are calculated using column 3; Table 3, column 4; and Table 4, column 5. 

c. The study group included 298 coal-fired plants. In the ten-mile radius case, coal is displaced in whole or 

part at 35 of these plants (11.7% of the plants). In the 25-mile radius case, coal is displaced in whole or part at 

60 of these plants (20.1%). 

System Dispatch Factors 

System dispatch refers to the pattern in which power plants are turned on and off, and their power 

output ramped up and down, to meet changing load patterns. (For additional discussion, see 

Appendix A.) The concept of displacing coal generation with power from existing NGCC plants 

assumes that the NGCC plants are underutilized or idle when coal plants are operating. However, 

this is not necessarily the case. This can be illustrated by examining the monthly utilization of the 

coal and gas-fired plants in the study groups (Figure 9). As shown in the figure, the utilization of 

coal and combined cycle plants follows a similar pattern: utilization is highest in the summer and, 

to a lesser degree, in the winter, and lowest in the “shoulder” months of the spring and fall. The 

figure illustrates that when coal plant operation is at its highest and the most coal power can be 

displaced, NGCC plant operation is also at its highest and surplus gas-fired generation is 

therefore at its lowest. 

Figure 9. Monthly Capacity Factors in 2007 for Study Group Coal and NGCC Plants 

35%

38%

33%

36% 37%

47%

53%

63%

50%

42%

35%

38%

77%

70%

66%

69%

79%

81% 83%

77%

71% 73%

76%

79%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Capacity Factor

Combined Cycle Gas Plants Coal-Fired Plants

Source: Calculated by CRS from the EIA-906/920 and EIA-860 databases. 

Notes: For information on the study groups of coal and NGCC plants, see footnote 11. NGCC= natural gas 

combined cycle. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

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Figure 9 is a national, monthly picture of power plant dispatch. System dispatch actually takes 

place moment-to-moment, and at this level of detail the complexities in displacing coal with gas 

become further evident. Figure 10 graphically illustrates hourly dispatch at Plant Barry, a power 

plant in Alabama that has both coal and NGCC units at the same site. The data is for November 

2007, the month in which the NGCC units at Plant Barry had their lowest generation for the year 

and therefore, in principle, the most excess capacity available to displace coal.25 However, the 

graphic illustrates that even during this low utilization month for the NGCC units, there are still 

periods when the units were running near maximum output26 (e.g., November 6 to 9, and 27 to 

30). While there were periods when coal plant output was high and the NGCC units were shut 

down (e.g., November 4), creating the maximum opportunity to displace coal with gas, there were 

also periods when the NGCC units were available but potential coal displacement was reduced by 

limited operation of the coal units (e.g., November 18). These examples illustrate the level of 

detailed analysis required to realistically estimate the potential for changing plant dispatch to 

displace coal with natural gas. 

Figure 10. Hourly Coal and Combined Cycle Generation at Plant Barry 

November 2007

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Day of the Month

Gross Hourly Mw Output 

Hourly Coal 

Unit 

Generation

Hourly NGCC 

Generation

Source: Data downloaded from the EPA website at http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=

emissions.prepackaged_select. 

Natural Gas Supply and Price 

Large scale displacement of coal-fired generation by existing NGCC plants could result in a 

significant increase in U.S. gas demand. Table 6 compares the actual demand for natural gas for 

all purposes in 2007 with an illustrative estimate of the additional gas supplies needed if all of the 

25 According to U.S. EPA data, the gross output of the NGCC units at Plant Barry was 288,726 MWh in November 

2007. In comparison, the highest output was 532,040 MWh in August. The data was downloaded from the EPA website 

at http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.prepackaged_select. 

26 The NGCC units at Plant Barry have, according to the Platts Powermap database, a nominal total net winter capacity 

of 1,090 MW. However, the maximum output achievable at any point in time will vary with the ambient air 

temperature, which affects the density of the air flow into the combustion turbine units of a NGCC. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 20 

displaceable coal-fired generation (see Table 3) were actually replaced by existing NGCC plants. 

As discussed above, this maximum displacement of coal by existing NGCC plants may be 

unachievable, so results are also shown for a half and a quarter of the maximum. 

Table 6. Illustrative Estimates of Increased Natural Gas Demand For Coal 

Displacement Compared to Total National Demand 

Based on 2007 Data 

Hypothetical 

Maximum 

Displacement of 

Coal by Existing 

NGCC Plants 

(2007 data and 

85% capacity 

factor) 

Half of 

Hypothetical 

Maximum 

Displacement 

One Quarter 

of 

Hypothetical 

Maximum 

Displacement 

1. Additional MWh of NGCC Generation Needed 

to Displace Coal 

640,128,780 320,064,390 160,032,195 

2. Required Additional Natural Gas in Trillion 

Btus (Tbtus) 

4,775 2,388 1,194 

3. Additional Gas as a Percentage of 2007 Gas 

Consumed for All Purposes in the U.S.a

20% 10% 5% 

Source: Table 3 and EIA, Annual Energy Review 2008, Tables 6.1 and A4 (http://www.eia.doe.gov/emeu/aer/

contents.html). 

Notes: Total gas consumption in 2007 of 23,047 billion cubic feet was converted to TBtus using a conversion 

factor of 1.028 (see Table A4 in the Annual Energy Review, cited immediately above). The MWh of additional gasfired generation was converted to TBtus using a heat rate of 7.4596 MMBtus of fuel input per MWh. This is the 

2007 average annual heat rate for the study group of 314 combined cycle plants, calculated using the generation 

and fuel input reported in the EIA 906/920 database (http://www.eia.doe.gov/cneaf/electricity/page/

eia906_920.html).

a. Total gas consumption in 2007 for all residential, commercial, industrial, electric power, and transportation 

purposes was 23,692 Tbtus. The percentages shown in Line 3 are calculated by dividing this number into the 

values shown on line 2. 

Total U.S. natural gas demand in 2007 was the third highest on record. The illustrative estimates 

of increased gas demand for coal displacement would increase the already high level of demand 

in 2007 by another 5% to 20% (Table 6, line 3). 

This increased demand might be met with a combination of increased domestic production, 

pipeline imports from Canada, Alaskan supplies if the trans-Alaskan gas pipeline is built, and 

imports of liquefied natural gas by tanker from overseas. For example, one reason for the interest 

in coal displacement by gas is the recent increase in natural gas available from shale formations 

and other “unconventional” sources of gas.27 The combination of higher production (up a 

projected 3.7% for 2009) and reduced demand due to the 2008-2009 recession has contributed to 

a sharp decline in gas prices from the peaks experienced earlier in the 2000s (see Figure 3).28 For 

27 For additional information see CRS Report R40894, Unconventional Gas Shales: Development, Technology, and 

Policy Issues, coordinated by Anthony Andrews; and FERC, State of the Markets Report 2008, August 2009, Section 2, 

http://www.ferc.gov/market-oversight/st-mkt-ovr/2008-som-final.pdf. 

28 EIA, Short-Term Energy Outlook, December 2009, pp. 4 – 6, http://www.eia.doe.gov/emeu/steo/pub/dec09.pdf. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 21 

the longer term, there is widespread optimism concerning the gas supply and price outlook. An 

example is a late 2009 assessment by the Federal Energy Regulatory Commission (FERC): 

The long-term [gas production] story is one of abundance. In June, the Potential Gas 

Committee, an independent group that develops biennial assessments of gas resources, raised 

its estimate to over 2 quadrillion cubic feet, one-third more than its previous level and almost 

100 years of gas production at current consumption levels. The large increase is almost 

entirely due to improvements in our ability to harvest gas from shale and get it to markets at 

a reasonable cost.... As we have indicated before, gas production is becoming more like 

mining and manufacturing with high probability of production from each well drilled. This 

environment should have profound effects on the traditional boom and bust cycle of gas 

production.29

EIA’s most recent long-term forecasts of natural gas wellhead prices for 2020 and 2030 have 

dropped, respectively, 13% and 11% from its prior forecast, “due to a more rapid ramping up of 

shale gas production, particularly after 2015. [The forecast] assumes a larger resource base for 

natural gas, based on a reevaluation of shale gas and other resources....”30

Even with the current optimism concerning natural gas supplies and prices, it is important to note 

that natural gas markets have historically been exceptionally difficult to forecast. According to an 

EIA self-assessment of its long-term projections, “The fuel with the largest difference between 

the projections and actual data has generally been natural gas.”31 In the 1990s gas prices were 

expected to be low; by 2004 prices were much higher than expected and major gas buyers were 

reported to be “increasingly critical of the nation’s system for forecasting natural gas supply and 

demand.”32 Subsequently, as shown in Figure 3, prices plummeted. In the October 2009 Senate 

hearing on natural gas, a cautionary note was sounded by the witness for Dow Chemical 

Company: 

Although increased supply from shale gas appears to have changed the production profile, 

we have seen similar scenarios occur after past spikes. In 1998, significant new imports from 

Canada came on line; in 2002-2003, there were new supplies from the Gulf of Mexico and in 

2005, new discoveries in the Rockies were brought into play. In each case, the initial hopes 

were too high and production increases were not as large as initially expected.33

In 2009, as in 2002, 2004 and 2006, drilling has declined dramatically as price has fallen. 

After each trough, natural gas demand and price rise once the economy turns, signaling the 

production community to increase drilling. During the lag between the pricing signals and 

new production, only one mechanism exists to rebalance supply and demand: demand 

29 FERC, Winter 2009/2010 Energy Market Assessment, November 19, 2009, p. 3, http://www.ferc.gov/EventCalendar/

Files/20091119102759-A-3-final.pdf. For additional information on the findings of the Potential Gas Committee, see 

the press release at http://www.energyindepth.org/wp-content/uploads/2009/03/potential-gas-committee-reportsunprecedented-increase-in.pdf. 

30 EIA, Annual Energy Outlook 2010 Early Release Overview, pp. 3, 4, 12, http://www.eia.doe.gov/oiaf/aeo/pdf/

overview.pdf. 

31 EIA, Annual Energy Outlook Retrospective Review: Evaluation of Projections in Past Editions (1982-2008),

September 2008, p. 2, http://www.eia.doe.gov/oiaf/analysispaper/retrospective/pdf/0640%282008%29.pdf. 

32 Rebecca Smith, “Utilities Question Natural-Gas Forecasting,” The Wall Street Journal, December 27, 2004. 

33 Statement for the Record of Edward Stones, Director of Risk Management, Dow Chemical Co., before the Senate 

Energy and Natural Resources Committee hearing on The Role of Natural Gas in Mitigating Climate Change, October 

28, 2009, p. 4, http://energy.senate.gov/public/_files/StonesTestimony102809.pdf. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 22 

destruction brought about by price spikes. Demand destruction is an antiseptic economic 

term for job destruction.34

Although multiple options may exist to meet the additional natural gas demand created by a coal 

displacement policy, the significance of the potential increase in demand should not be 

underestimated. The lowest level of increased gas demand shown in Table 6, 1,194 trillion Btus 

(TBtus), would raise total demand to 24,886 TBtus. In its most recent Reference Case forecast, 

the U.S. Energy Information Administration (EIA) does not envision this demand level being 

reached until after 2028. The middle estimate of increased gas demand shown in Table 6 would 

raise total gas demand to 26,080 TBtus, which is larger than EIA’s forecast for 2035.35 A policy 

of rapid change from coal to gas could therefore involve a significant acceleration of gas demand 

growth compared to EIA’s current estimates. 

Natural Gas Transportation and Storage 

Gas-fired power plants and other gas consumers receive fuel through a vast national pipeline 

network. At the end of 2008 the network consisted of 293,000 miles of interstate and intrastate 

pipelines with the capacity to move up to 215 billion cubic feet (BCF) of gas daily.36 The 

capacity of this system is sized to meet peak loads, such as during the winter residential heating 

season. Peak demands are also supported by a system of natural gas storage facilities connected 

to the pipeline network. These storage facilities hold gas which is produced during lower demand 

periods until it is needed to meet peak demand. 

It seems unlikely that on a national, aggregate scale, pipeline capacity would be a constraint on 

coal displacement by existing NGCC plants. The natural gas consumption required for the 

maximum potential coal displacement by existing NGCC plants (see Table 3) equate to about 15 

BCF per day of natural gas, or about 7% of existing pipeline capacity.37 A 7% increase in peak 

demand would appear manageable given the planned expansions to the pipeline system (see 

below). But irrespective of national system-wide capacity, a different question is whether 

increased use of gas-fired plants could overstress the specific pipelines and storage facilities that 

serve those plants. This may be an important issue because the increase in gas demand from 

existing NGCC plants for coal displacement could be large relative to the amount of gas currently 

used for power generation. As shown in Table 7, illustrative estimates of this increase range from 

16% to 66%, which means that the facilities serving those plants could have to handle a material 

increase in gas demand. 

34 Ibid., p. 3. 

35 EIA’s Annual Energy Outlook 2010 backup spreadsheet for Table 13, located at http://www.eia.doe.gov/oiaf/aeo/

aeoref_tab.html. Values were converted from cubic feet to Btus using a conversion factor of 1.028. This is the 

Reference Case forecast, which assumes no changes to current law or regulations. 

36 The interstate portion of the system consists of 217,000 miles of pipeline with a capacity of 183 BCF per day. The 

interstate portion consists of 76,000 miles of pipeline with a capacity of 32 BCF per day. EIA, Expansion of the U.S. 

Natural Gas Pipeline Network: Additions in 2008 and Projects through 2011, September 2009, p. 3, 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2009/pipelinenetwork/pipelinenetwork.pdf. 

37 As shown in Table 3, the maximum potential increase in existing NGCC generation to displace coal is 640,128,780 

MWh. This number assumes an annual average capacity factor of 85%, but on a given day the existing NGCC plants 

could be running at full load to displace coal, which is 640,128,780 MWh ÷ 0.85 ÷ 365 days = 2,063,268 MWh per 

day. The average heat rate for combined cycles in the study group is 7.4596 MMBtus per MWh and the conversion 

factor from MMBtus of thousands of cubic feet is 1.028, so the daily gas demand can be calculated as 2,063,268 MWh 

x 7.4596 MMBtus per MWh ÷ 1.028 ÷ 1,000,000 = 15 BCF per day. 
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Congressional Research Service 23 

A balancing factor is that the natural gas industry has been effective at adding large amounts of 

capacity to the pipeline system. Capacity additions in 2007 and 2008 were, respectively, 14.9 and 

44.6 BCF per day, and as of mid-2009, 31.9 BCF per day was under construction or approved for 

construction and completion in 2009. Another 62.1 BCF per day of capacity additions are 

planned for 2010 and 2011,38 which is equivalent to almost 30% of current capacity. It appears 

that, given sufficient lead time, the natural gas industry has the ability to install large amounts of 

additional transportation capacity to meet increased demand. 

Table 7. Illustrative Estimates of Increased Natural Gas Demand Relative to Electric 

Power Demand, Based on 2007 Data 

Hypothetical 

Maximum 

Displacement of 

Coal by Existing 

NGCC Plants 

(2007 data and 

85% capacity 

factor) 

Half of 

Hypothetical 

Maximum 

Displacement 

One Quarter 

of 

Hypothetical 

Maximum 

Displacement 

1. Additional MWh of Existing NGCC Generation 640,128,780 320,064,390 160,032,195 

2. Required Additional Natural Gas in Trillion 

Btus (Tbtus) 

4,775 2,388 1,194 

3. Required Additional Gas as a Percentage of 

Actual Gas Used for Power Generation in 2007a

66% 33% 16% 

Source: Table 6 and EIA, Annual Energy Review 2008, Tables 8.4a (http://www.eia.doe.gov/emeu/aer/

contents.html). 

Notes: The MWh of additional gas-fired generation was converted to TBtus using a heat rate of 7.4596 MMBtus 

of fuel input per MWh. This is the 2007 average annual heat rate for the study group of 314 combined cycle

plants, calculated using the generation and fuel input reported in the EIA 906/920 database 

(http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html).

a. Electric power gas consumption in 2007 was 7,288 Tbtus. The percentages shown in Line 3 are calculated 

by dividing this number into the values shown on line 2. 

Policy Considerations 

As discussed in this report, the potential for displacing coal consumption in the power sector by 

making greater use of existing NGCC power plants depends on numerous factors. These include: 

• The amount of excess NGCC generating capacity available; 

• The current operating patterns of coal and NGCC plants, and the amount of 

flexibility power system operators have for changing those patterns; 

• Whether or not the transmission grid can deliver power from existing NGCC 

plants to loads currently served by coal plants; and 

38 EIA, Expansion of the U.S. Natural Gas Pipeline Network: Additions in 2008 and Projects through 2011, September 

2009, Table 2, http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2009/pipelinenetwork/

pipelinenetwork.pdf. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

Congressional Research Service 24 

• Whether there is sufficient natural gas supply, and pipeline and gas storage 

capacity, to deliver large amounts of additional fuel to gas-fired power plants; 

and consideration of the environmental impacts of increasing gas production. 

All of these factors have a time dimension. For example, while existing NGCC plants may have 

sufficient excess capacity today to displace a material amount of coal generation, this could 

change in the future as load grows. Therefore a full analysis of the potential for gas displacement 

of coal must take into account future conditions, not just a snapshot of the current situation. 

There is also the question of cost which, as discussed in the introduction, is beyond the scope of 

this report. Clearly, the cost of a coal displacement by gas policy is highly uncertain, and depends 

on such factors as future natural gas and coal prices, any need to build additional pipeline and 

transmission line facilities, and the cost of carbon (if any). The economic impacts of a coal 

displacement by gas policy could also spill over to other parts of the economy. For example, 

increased power sector demand could drive up the price of natural gas, to the detriment of other 

residential, commercial, and industrial users. Decreased production of coal and increased 

production of natural gas would pose varying costs and benefits for states and regions. 

As a step toward addressing these questions, Congress may consider chartering a rigorous study 

of the potential for displacing coal with power from existing gas-fired power plants. Such a study 

would require sophisticated computer modeling to simulate the operation of the power system, to 

determine whether there is sufficient excess gas fired capacity and the supporting transmission 

and other infrastructure to displace a significant volume of coal over the near term. This kind of 

study might also estimate the direct costs of a gas for coal policy, such as the impact on electric 

rates. Because of the large number of uncertainties, such as the future price of natural gas, the 

study would have to consider several scenarios. Such a study could help Congress judge whether 

there is sufficient potential to further explore a policy of replacing coal generation with increased 

output from existing gas-fired plants. 

Congress may also consider chartering an analysis of the potential for directly using gas in 

existing coal-fired plants, either as a supplemental or primary fuel. As noted in the introduction, 

large scale use of gas in coal plants raises engineering issues and the question of how many coal 

plants have adequate pipeline connections. However, burning gas in coal plants would make it 

possible to displace coal while still using existing transmission lines to meet load, which could be 

a significant advantage.39

39 Many coal plants use natural gas as a startup fuel and for flame stabilization during normal operations. However, this 

is different from running the plant primarily or largely on natural gas. In addition to the engineering issues, even if a 

coal plant currently uses natural gas as a startup fuel, its existing natural gas pipeline connection may not have 

sufficient capacity to provide enough gas for full load (or even large partial load) operation on gas. There are examples 

of coal units switching to natural gas for environmental reasons (“Marketwatch: Public Service Electric & Gas of New 

Jersey,” Platts Coal Week, June 22, 1992; “Ill. Power to Shift Vermilion to Gas; Phase I Decision Kills Coal 

Solicitation,” Platts Coal Week, October 10, 1994; “PEPCO Mulls NOx Ozone Season’s Effect on Coal, Gas, Oil Use,” 

Platts Coal Week, October 25, 1999. 
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Appendix A. Background on the Electric Power 

System 

This appendix provides background on the components and operation of the electric power 

system. Readers familiar with these topics may wish to skim or skip this appendix. 

Power Plants and Power Lines 

Power plants, transmission systems, and distribution systems constitute the major components of 

the existing electric power system, as briefly described and illustrated below (Figure A-1): 

• Generating plants produce electricity, using either combustible fuels such as 

coal, natural gas, and biomass; or non-combustible energy sources such as wind, 

solar energy, or nuclear fuel. 

• Transmission lines carry electricity from power plants to demand centers. The 

higher the voltage of a transmission line the more power it can carry and the 

fewer the line losses during transmission. Current policy discussions focus on 

the high voltage network (230 kilovolts (kV) rating and greater) used to move 

large amounts of power long distances. 

• Near customers a step-down transformer reduces voltage so the power can be 

carried by low voltage distribution lines for final delivery. 

Figure A-1. Elements of the Electric Power System 

Source: CRS. 
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Capacity and Energy 

Capacity is the potential instantaneous output of a generating or storage unit, measured in watts. 

Energy is the actual amount of electricity generated by a power plant or released by a storage 

device during a time period, measured in watt-hours. The units are usually expressed in 

thousands (kilowatts and kilowatt-hours) or millions (megawatts and megawatt-hours). For 

example, the maximum amount of power a 1,000 megawatt (MW) power plant can generate in a 

year is 8.76 million megawatt-hours (MWh), calculated as: 1,000 MW x 8,760 hours in a year = 

8.76 million MWh. 

Capacity Factor 

Capacity factor is a standard measure of how intensively a power plant is utilized. It is the ratio 

of how much electricity a power plant produced over a period of time, typically a year, compared 

to how much electricity the plant could have produced if it operated continuously at full output. 

For example, as shown in the prior paragraph, the maximum possible output of a 1,000 MW 

power plant in one year is 8.76 million MWh. Assume that during a year the plant actually 

produced only 7.0 million MWh. In this case the plant’s capacity factor would be 7.0 million 

MWh ÷ 8.76 million MWh = 81%. 

Generation and Load 

The demand for electricity (“load”) faced by an electric power system varies moment to moment 

with changes in business and residential activity and the weather. Load begins growing in the 

morning as people waken, peaks in the early afternoon, and bottoms-out in the late evening and 

early morning. Figure A-2 shows an illustrative daily load curve. 

The daily load shape dictates how electric power systems are operated. As shown in Figure A-2,

there is a minimum demand for electricity that occurs throughout the day. This base level of 

demand is met with “baseload” generating units which have low variable operating costs.40

Baseload units can also meet some of the demand above the base, and can reduce output when 

demand is unusually low. The units do this by “ramping” generation up and down to meet 

fluctuations in demand. 

The greater part of the daily up and down swings in demand is met with “intermediate” units 

(also referred to as load-following or cycling units). These units can quickly change their output 

to match the change in demand (that is, they have a fast “ramp rate”). Load-following plants can 

also serve as “spinning reserve” units that are running but not putting power on the grid, and are 

immediately available to meet unanticipated increases in load or to back up other units that go 

off-line due to breakdowns. 

40 Variable costs are costs that vary directly with changes in output. For fossil fuel units the most important variable 

cost is fuel. Solar and wind plants have minimal or no variable costs, and nuclear plants have low variable costs. 
Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants 

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Figure A-2. Illustrative Daily Load Curve 

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Hourly Load (MW)

Midnight to Midnight

This report covers 

generating 

technologies used 

to meet 

intermediate and 

baseload demand.

Peak

Demand

Intermediate

Demand

Baseload

Demand

Source: CRS. 

The highest daily loads are met with peaking units. These units are typically the most expensive 

to operate, but can quickly start up and shut down to meet brief peaks in demand. Peaking units 

also serve as spinning reserve and as “quick start” units able to go from shutdown to full load in 

minutes. A peaking unit typically operates for only a few hundred hours a year. 

Economic Dispatch and Heat Rate 

The generating units available to meet system load are “dispatched” (put on-line) in order of 

lowest variable cost. This is referred to as the “economic dispatch” of a power system’s plants. 

For a plant that uses combustible fuels (such as coal or natural gas) a key driver of variable costs 

is the efficiency with which the plant converts fuel to electricity, as measured by the plant’s “heat 

rate.” This is the fuel input in British Thermal Units (btus) needed to produce one kilowatt-hour 

of electricity output. A lower heat rate equates with greater efficiency and lower variable costs. 

Other things (most importantly, fuel and environmental compliance costs) being equal, the lower 

a plant’s heat rate, the higher it will stand in the economic dispatch priority order. Heat rates are 

inapplicable to plants that do not use combustible fuels, such as nuclear and non-biomass 

renewable plants. 

As an illustration of economic dispatch, consider a utility system with coal, nuclear, geothermal, 

natural gas combined cycle, and natural gas peaking units in its system: 

(1) Nuclear, coal, and geothermal baseload units, which are expensive to build but have 

low fuel costs and therefore low variable costs, will be the first units to be put online. Other than for planned and forced maintenance, these baseload generators will 

run throughout the year. 

(2) Combined cycle units, which are very efficient but use more expensive natural gas as 

a fuel, will meet intermediate load. These cycling plants will ramp up and down 

during the day, and will be turned on and off dozens of times a year. 
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(3) Peaking plants, using combustion turbines,41 are relatively inefficient and burn 

natural gas. They run only as needed to meet the highest loads.42

An exception to this straightforward economic dispatch are “variable renewable” power plants—

wind and solar—that do not fall neatly into the categories of baseload, intermediate, and peaking 

plants. Variable renewable generation is used as available to meet demand. Because these 

resources have very low variable costs they are ideally used to displace generation from gas-fired 

combined cycle plants and peaking units with higher variable costs. However, if wind or solar 

generation is available when demand is low (such as a weekend or, in the case of wind, in the 

evening), the renewable output could displace coal generation. 

Power systems must meet all firm loads at all times, but variable renewable plants do not have 

firm levels of output because they depend on the weather. They are not firm resources because 

there is no guarantee that the plant can generate at a specific load level at a given point in time.43

Variable renewable generation can be made firm by linking wind and solar plants to electricity 

storage, but with current technology, storage options are limited and expensive. 

41 A combustion turbine is an adaption of jet engine technology to electric power generation. A combustion turbine can 

either be used stand-alone as a peaking unit, or as part of a more complex combined cycle plant used to meet

intermediate and baseload demand. 

42 This alignment of generating technologies is for new construction using current technology. The existing mix of 

generating units in the United States contains many exceptions to this alignment of load to types of generating plants, 

due to changes in technology and economics. For instance, there are natural gas and oil-fired units built decades ago as 

baseload stations that now operate as cycling or peaking plants because high fuel prices and poor efficiency has made 

them economically marginal. Some of these older plants were built close to load centers and are now used as reliability 

must-run (RMR) generators that under certain circumstances must be operated, regardless of cost, to maintain the 

stability of the transmission grid. 

43 Hydroelectric generation is a special case. Hydro generation is very low cost and is firm, dispatchable capacity to the 

degree there is water in the dam’s reservoir. However, operators have to consider not only how much water is currently 

available, but how much may be available in upcoming months, and competing demands for the water, such as drinking 

water supply, irrigation, and recreation. These factors can make hydro dispatch decisions very complex. In general

hydro is used to meet load during high demand hours, when it can displace expensive peaking and cycling units, but if 

hydro is abundant it can also displace baseload coal plants. 
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Appendix B. Combined Cycle Technology 

The combined cycle achieves a high level of efficiency by capturing waste heat that would 

otherwise be lost in the generating process. As shown in Figure B-1 for a combined cycle unit 

fueled by natural gas, the gas is fed into a combustion turbine which burns the fuel to power a 

generator. The exhaust from the combustion turbine is then directed to a specialized type of 

boiler (the heat recovery steam generator or HRSG) where the heat in the exhaust gases is used to 

produce steam, which in turn drives a second generator. In combined heat and power (CHP) 

applications, part of the steam is used to support an industrial process or to provide space heating, 

further increasing the total energy efficiency of the system. 

Figure B-1. Schematic of a Combined Cycle Power Plant 

Source: CRS, based on a Calpine Corp. illustration. 

Combined cycles are built in different configurations, depending in part on the amount of 

capacity needed. Figure B-1 illustrates a configuration in which one combustion turbine feeds 

one HRSG; this is referred to as “1x1” design. In higher capacity 2x1 or 3x1 designs, multiple 

combustion turbines feed a single HRSG. These options illustrate the modular (or “building 

block”) nature of combined cycles, which facilitates rapid and flexible construction of new 

generating units to match changes in demand. 

In the United States the predominant fuel used in combined cycle plants is natural gas. Combined 

cycles can also be designed to use fuel oil as a primary or backup fuel. Gasified coal can also be 

used as the fuel in an integrated gasification combined cycle (IGCC) plant. There are currently 

two prototype IGCC plant operating in the United States and a commercial-scale unit is under 

construction in Indiana. 
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Author Contact Information 

Stan Mark Kaplan 

Specialist in Energy and Environmental Policy 

skaplan@crs.loc.gov, 7-9529