# Power Plants: Characteristics and Costs

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URL: https://www.frixlaw.com/law-library/documents/crs%3ARL34746

## Record

- **Collection:** Congressional research report
- **Document type:** CRS Report
- **Published:** November 13, 2008
- **Citation:** RL34746

## Text

Power Plants: Characteristics and Costs
(name redacted)
Specialist in Energy and Environmental Policy
November 13, 2008

Congressional Research Service
7-....
www.crs.gov
RL34746

CRS Report for Congress
Prepared for Members and Committees of Congress

Power Plants: Characteristics and Costs

Summary
This report analyzes the factors that determine the cost of electricity from new power plants.
These factors—including construction costs, fuel expense, environmental regulations, and
financing costs—can all be affected by government energy, environmental, and economic
policies. Government decisions to influence, or not influence, these factors can largely determine
the kind of power plants that are built in the future. For example, government policies aimed at
reducing the cost of constructing power plants could especially benefit nuclear plants, which are
costly to build. Policies that reduce the cost of fossil fuels could benefit natural gas plants, which
are inexpensive to build but rely on an expensive fuel.
The report provides projections of the possible cost of power from new fossil, nuclear, and
renewable plants built in 2015, illustrating how different assumptions, such as for the availability
of federal incentives, change the cost rankings of the technologies.
None of the projections is intended to be a “most likely” case. Future uncertainties preclude firm
forecasts. The rankings of the technologies by cost are therefore also an approximation and
should not be viewed as definitive estimates of the relative cost-competitiveness of each option.
The value of the discussion is not as a source of point estimates of future power costs, but as a
source of insight into the factors that can determine future outcomes, including factors that can be
influenced by the Congress.
Key observations include the following:
•

Government incentives can change the relative costs of the generating
technologies. For example, federal loan guarantees can turn nuclear power from a
high cost technology to a relatively low cost option.

•

The natural gas-fired combined cycle power plant, the most commonly built type
of large natural gas plant, is a competitive generating technology under a wide
variety of assumptions for fuel price, construction cost, government incentives,
and carbon controls. This raises the possibility that power plant developers will
continue to follow the pattern of the 1990s and rely heavily on natural gas plants
to meet the need for new generating capacity.

•

With current technology, coal-fired power plants using carbon capture equipment
are an expensive source of electricity in a carbon control case. Other power
sources, such as wind, nuclear, geothermal, and the natural gas combined cycle
without capture technology currently appear to be more economical.

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Power Plants: Characteristics and Costs

Contents
Introduction and Organization .....................................................................................................1
Types of Generating Technologies...............................................................................................2
Electricity Demand and Power Plant Choice and Operation...................................................2
Generation and Load.......................................................................................................2
Economic Dispatch and Heat Rate...................................................................................3
Capacity Factor...............................................................................................................4
Utility Scale Generating Technologies...................................................................................5
Supercritical Pulverized Coal ..........................................................................................6
Integrated Gasification Combined Cycle (IGCC).............................................................7
Natural Gas Combined Cycle ..........................................................................................8
Nuclear Power ................................................................................................................9
Geothermal Power ........................................................................................................ 10
Wind Power .................................................................................................................. 10
Solar Thermal and Solar Photovoltaic (PV) Power ........................................................ 10
Factors that Drive Power Plant Costs......................................................................................... 11
Government Incentives ....................................................................................................... 11
Renewable Energy Production Tax Credit ..................................................................... 12
Nuclear energy production tax credit ............................................................................. 12
Loan Guarantees for Nuclear and Other Carbon-Control Technologies .......................... 12
Energy Investment Tax Credit ....................................................................................... 13
Clean Coal Technologies Investment Tax Credit ............................................................ 14
State and Local Incentives............................................................................................. 14
Capital and Financing Costs ................................................................................................ 15
Construction Cost Components and Trends ................................................................... 15
Financing Power Plant Projects ..................................................................................... 17
Fuel Costs ........................................................................................................................... 20
Air Emissions Controls for Coal and Gas Plants .................................................................. 22
Conventional Emissions ................................................................................................ 23
Carbon Dioxide............................................................................................................. 25
Financial Analysis Methodology and Key Assumptions............................................................. 30
Analysis of Power Project Costs................................................................................................ 31
Case 1: Base Case............................................................................................................... 32
Key Observations.......................................................................................................... 32
Discussion .................................................................................................................... 32
Case 2: Influence of Federal and State Incentives ................................................................ 37
Key Observations.......................................................................................................... 37
Discussion .................................................................................................................... 37
Case 3: Higher Natural Gas Prices....................................................................................... 40
Key Observations.......................................................................................................... 40
Discussion .................................................................................................................... 41
Case 4: Uncertainty in Capital Costs ................................................................................... 43
Key Observations.......................................................................................................... 43
Discussion .................................................................................................................... 44
Case 5: Carbon Controls and Costs...................................................................................... 45
Key Observations.......................................................................................................... 45
Discussion .................................................................................................................... 45
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Power Plants: Characteristics and Costs

Figures
Figure 1. Illustrative Load Curve.................................................................................................3
Figure 2. Total U.S. Electric Power Generation by Energy Source, 2007......................................7
Figure 3. Coal and Natural Gas Constant Dollar Price Trends .................................................... 21
Figure 4. Uranium Price Trends................................................................................................. 22
Figure 5. EIA’s Projections of S. 2191 CO2 Allowance Prices (2006$ per Metric Ton of
CO2 Equivalent) ..................................................................................................................... 29
Figure 6. Comparison of EIA’s Reference Case Coal Prices and S. 2191 Core Case CO2
Allowance Prices ................................................................................................................... 30
Figure 7. Natural Gas Price Trends (Henry Hub Spot Price)....................................................... 41
Figure 8. Projection of Natural Gas Prices to Electric Power Plants, 2006 $ per MMBtu............ 42
Figure A-1. Process Schematic: Pulverized Coal without Carbon Capture.................................. 52
Figure A-2. Process Schematic: Pulverized Coal with Carbon Capture....................................... 52
Figure A-3. Representative Pulverized Coal Plant: Gavin Plant (Ohio) ...................................... 53
Figure A-4. Process Schematic: IGCC without Carbon Capture................................................. 53
Figure A-5. Process Schematic: IGCC with Carbon Capture...................................................... 54
Figure A-6. Representative IGCC Plant: Polk Plant (Florida)..................................................... 54
Figure A-7. Process Schematic: Combined Cycle Power Plant................................................... 55
Figure A-8. Representative Combined Cycle: McClain Plant (Oklahoma).................................. 55
Figure A-9. Process Schematic: Pressurized Water Reactor (PWR)........................................... 56
Figure A-10. Process Schematic: Boiling Water Reactor (BWR)............................................... 57
Figure A-11. Representative Gen III/III+ Nuclear Plant: Rendering of the Westinghouse
AP1000 (Levy County Project, Florida) ................................................................................. 58
Figure A-12. Schematic of a Wind Turbine................................................................................ 58
Figure A-13. Representative Wind Farm: Gray County Wind Farm (Kansas) ............................. 59
Figure A-14. Wind Turbine Size and Scale (FPL Energy) .......................................................... 59
Figure A-15. Process Schematic: Binary Cycle Geothermal Plant .............................................. 60
Figure A-16. Representative Geothermal Plant: Raft River Plant (Idaho) ................................... 60
Figure A-17. Process Schematic: Parabolic Trough Solar Thermal Plant .................................... 61
Figure A-18. Representative Solar Thermal Plant: Nevada Solar One ........................................ 61
Figure A-19. Nevada Solar One: Parabolic Collector Detail....................................................... 61
Figure A-20. Process Schematic: Central Station Solar Photovoltaic Power ............................... 62
Figure A-21. Representative Solar PV Plant: Nellis Air Force Base (Nevada) ............................ 63
Figure A-22. Nellis AFB Photovoltaic Array Detail ................................................................... 63
Figure B-1. Pulverized Coal Project Cost Trends ....................................................................... 69
Figure B-2. IGCC Project Cost Trends ...................................................................................... 72

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Figure B-3. Nuclear Project Cost Trends ................................................................................... 76
Figure B-4. Combined Cycle Project Cost Trends...................................................................... 79
Figure B-5. Wind Project Cost Trends ....................................................................................... 82
Figure B-6. Geothermal Project Cost Trends ............................................................................. 84
Figure B-7. Solar Thermal Project Cost Trends.......................................................................... 87
Figure B-8. Solar PV Project Cost Trends.................................................................................. 89

Tables
Table 1. Shares of Total National Electric Generation and Generating Capacity, 2006................ 18
Table 2. Emission Controls as an Estimated Percentage of Total Costs for a New
Pulverized Coal Plant............................................................................................................. 25
Table 3. Estimates of the Change in IGCC Plant Capacity and Capital Cost from Adding
Carbon Capture...................................................................................................................... 27
Table 4. Estimated Base Case Results........................................................................................ 34
Table 5. Benchmark Comparison to Natural Gas Combined Cycle Plant Power Costs:
Base Case Values ................................................................................................................... 36
Table 6. Effect of Public Power Financing on Base Case Results ............................................... 37
Table 7. Power Costs with Additional Government Incentives ................................................... 39
Table 8. Benchmark Comparison to Combined Cycle Power Costs: Additional
Government Incentives .......................................................................................................... 40
Table 9. Benchmark Comparison to Natural Gas Combined Cycle Plant Power Costs:
50% Higher Gas Price............................................................................................................ 42
Table 10. Change in the Base Case Gas Price Needed to Equalize the Cost of Combined
Cycle Power with Other Technologies .................................................................................... 43
Table 11. Effect of Higher and Lower Capital Costs on the Cost of Power ................................. 44
Table 12. Benchmark Comparison to Combined Cycle Power Costs: Higher and Lower
Capital Costs.......................................................................................................................... 45
Table 13. Effect of Current Technology Carbon Controls on Power Plant Capital Cost and
Efficiency .............................................................................................................................. 46
Table 14. Estimated Annualized Cost of Power with Carbon Controls........................................ 48
Table 15. Change in the Price of Natural Gas Required to Equalize the Cost of Combined
Cycle Generation (Without Carbon Controls) with Other Technologies................................... 50
Table 16. Cost of Power with Base and Reduced Carbon Capture Cost and Efficiency
Impacts .................................................................................................................................. 51
Table B-1. Pulverized Coal Projects Selected for Cost Estimate................................................. 66
Table B-2. Coal Integrated Gasification Combined Cycle (IGCC) Projects Selected for
Cost Estimate......................................................................................................................... 70
Table B-3. Nuclear Projects Selected for Cost Estimate ............................................................. 73
Table B-4. Combined Cycle Projects Selected for Cost Estimate................................................ 77

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Table B-5. Wind Projects Selected for Cost Estimate ................................................................. 80
Table B-6. Geothermal Projects Selected for Cost Estimate ....................................................... 83
Table B-7. Solar Thermal Projects Selected for Cost Estimate ................................................... 85
Table B-8. Solar Photovoltaic (PV) Projects Selected for Cost Estimate..................................... 88
Table D-1. Financial Factors ..................................................................................................... 93
Table D-2. Power Plant Technology Assumptions...................................................................... 94
Table D-3. Air Emission Characteristics .................................................................................... 95
Table D-4. Fuel and Allowance Price Projections (Selected Years)............................................. 96

Appendixes
Appendix A. Power Generation Technology Process Diagrams and Images ............................... 52
Appendix B. Estimates of Power Plant Overnight Costs ............................................................ 64
Appendix C. Estimates of Technology Costs and Efficiency with Carbon Capture ..................... 90
Appendix D. Financial and Operating Assumptions ................................................................... 93
Appendix E. List of Acronyms and Abbreviations ..................................................................... 97

Contacts
Author Contact Information ...................................................................................................... 98

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Power Plants: Characteristics and Costs

Introduction and Organization
The United States may have to build many new power plants to meet growing demand for electric
power. For example, the Energy Information Administration (EIA) estimates that the nation will
have to construct 226,000 megawatts of new electric power generating capacity by 2030.1 This is
the equivalent of about 450 large power plants. Whatever the number of plants actually built,
different combinations of fossil, nuclear, or renewable plants could be built to meet the demand
for new generating capacity. Congress can largely determine which kinds of plants are actually
built through energy, environmental, and economic policies that influence power plant costs.
This report analyzes the factors that determine the cost of electricity from new power plants.
These factors—including construction costs, fuel expense, environmental regulations, and
financing costs—can all be affected by government energy and economic policies. Government
decisions to influence, or not influence, these factors can largely determine the kind of power
plants that are built in the future. For example, government policies aimed at reducing the cost of
constructing power plants could especially benefit nuclear plants, which are costly to build.
Policies that reduce the cost of fossil fuels could benefit natural gas plants, which are inexpensive
to build but rely on an expensive fuel.
The report provides projections of the possible cost of power for new fossil, nuclear, and
renewable plants built in 2015. The projections illustrate how different assumptions, such as for
the availability of federal incentives, change the cost rankings of the technologies. Key
observations include the following:
•

Government incentives can change the relative costs of the generating
technologies. For example, federal loan guarantees can turn nuclear power from a
high cost technology to a relatively low cost option.

•

The natural gas-fired combined cycle power plant, the most commonly built type
of large natural gas plant, is a competitive generating technology under a wide
variety of assumptions for fuel price, construction cost, government incentives,
and carbon controls. This raises the possibility that power plant developers will
continue to follow the pattern of the 1990s and rely heavily on natural gas plants
to meet the need for new power generation.

•

With current technology, coal-fired power plants using carbon capture equipment
are an expensive source of electricity in a carbon control case. Other power
sources, such as wind, nuclear, geothermal, and the natural gas combined cycle
plant without capture technology, currently appear to be more economical.

None of the projections is intended to be a “most likely” case. Future uncertainties preclude firm
forecasts. The value of this discussion is not as a source of point estimates of future power costs,
but as a source of insight into the factors that can determine future outcomes, including factors
that can be influenced by the Congress.

1

EIA, an independent arm of the Department of Energy, is the primary public source of energy statistics and forecasts
for the United States. The estimated amount of new generating capacity is taken from the Excel output spreadsheet for
the Annual Energy Outlook 2008 report. Note that EIA forecasts assume no change to the laws and regulations in effect
at the time the forecasts are made.

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The main body of report is divided into the following sections:
•

Types of generating technologies;

•

Factors that drive power plant costs;

•

Financial analysis methodology;

•

Analysis of power project costs.

The report also includes the following appendixes:
•

Appendix A presents power generation technology process diagrams and images.

•

Appendix B and Appendix C provide the data supporting the capital cost
estimates used in the economic analysis. Appendix C also shows how operating
costs and plant efficiencies were estimated for certain carbon control
technologies.

•

Appendix D presents the financial and operating assumptions used in the power
cost estimates.

•

Appendix E is a list of acronyms used in the report.

Types of Generating Technologies
The first part of this section describes how the characteristics of electricity demand influence
power plant choice and operation. The next part describes the generating technologies analyzed in
the report.

Electricity Demand and Power Plant Choice and Operation
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 1 is an illustrative daily load curve.
The daily load shape dictates how electric power systems are operated. As shown in Figure 1,
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.2
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 are met with “intermediate” units
(also referred to as load-following or cycling units). These units can quickly change their output
2

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.

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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.
Figure 1. Illustrative Load Curve

16,000

Peak
Demand

Hourly Load (MW)

14,000
12,000

Intermediate
Demand

10,000
8,000

Baseload
Demand

6,000

This report covers
generating
technologies used
to meet
intermediate and
baseload demand.

4,000
2,000
Midnight to Midnight

The highest daily loads are met with peaking units. These units are typically the most expensive
to operate, but can quickly startup and shutdown 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:
•

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 on line. Other than for planned and forced maintenance, these baseload
generators will run throughout the year.

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•

Combined cycle units, which are very efficient but use 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.

•

Peaking plants, using combustion turbines,3 are relatively inefficient and burn
expensive natural gas. They run only as needed to meet the highest loads.4

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 are dependent 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. 5 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.6

Capacity Factor
As discussed above, baseload units run more often than cycling units, and peaking units operate
the least often. The utilization of a generating unit is measured by its “capacity factor.” This is the
ratio of the amount of power generated by a unit for a period of time (typically a year) to the
maximum amount of power the unit could have generated if it operated at full output, non-stop.
For example, the maximum amount of power a 1,000 megawatt (MW) unit 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.

3

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.
4
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.
5
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 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.
6
For example, a solar project developer decided to leave storage and other “extras” out of a proposed plant in order to
make it “commercially viable.” “Storage: Solar Power’s Next Frontier,” Platts Global Power Report, November 1,
2007.

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If this unit actually produced only 4.0 million Mwh its capacity factor would be 46% (calculated
as 4.0 million Mwh divided by 8.76 million Mwh).
Note in this calculation the distinction between capacity and energy. Capacity is the potential
instantaneous output of a generating unit, measured in watts.7 Energy is the actual amount of
electricity generated by a power plant 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).
The difference between actual and theoretical maximum output is caused by planned
maintenance, mechanical breakdowns (forced outages), and any instances in which the plant is
backed-down from maximum output due to lack of load or because the plant’s power is more
expensive than that from other plants. It is rare for a plant to have a capacity factor of 100%.
Baseload plants typically have capacity factors of about 70% or greater, peaking plants about
25% or less, and cycling plants fall in the middle.

Utility Scale Generating Technologies
The types of generating technologies discussed in this report are often referred to as “utility
scale” plants for baseload or intermediate service. These technologies generate large amounts of
electricity at a single site for transmission to customers. In 2006, large baseload and intermediate
service power plants accounted for about 86% of total power generation in the United States.8
Utility scale plants typically have generating capacities ranging from dozens to over a thousand
megawatts.
The one smaller scale generating technology covered in this report is solar photovoltaic power.
The capacity of the largest U.S. central station solar photovoltaic plant, at Nellis Air Force Base
in Nevada, is only 14 MW. Because of their small size, high capital costs, and low utilization
rates, solar photovoltaic plants built with current technology have very high electricity production
costs. Central station solar photovoltaic power is nonetheless included in the cost analysis
because of public interest.
The report excludes peaking plants, which play an important but small role in the power system.
The report also excludes oil-fired generation, which has all but disappeared from the nation’s
generating mix because of the high cost of the fuel. In 1978, oil-fired plants produced 22% of the
7
There are different measures of capacity. Nameplate capacity is the nominal maximum output of a generator, and
gross capacity is the actual maximum output. Net capacity is gross output minus the electricity needed to operate the
plant. Net capacity is therefore the amount of capacity that can actually put electric power on the grid. Net capacity can
vary with air and water temperatures, so a further distinction is made between summer and winter net capacity.
Capacity factor is most commonly computed using net summer capacity.
8
The estimate of 86% of 2006 generation from large baseload and intermediate generating units was computed from
the EIA-860 (generating capacity) and EIA-906/920 (generation) data files for 2006, available at
http://www.eia.doe.gov/cneaf/electricity/page/data.html. The calculation assumed that plants with a capacity factor of
25% or greater fall into the intermediate/baseload category, and that plants with a capacity of 200 MW or greater are
“large.” These thresholds are assumptions because there are no official categorizations of what constitutes intermediate,
baseload, or large power plants. However, large changes to the threshold values do not change the conclusion. For
example, if the capacity factor floor for what constitutes intermediate/baseload generation is increased to 33%, the
intermediate/baseload percentage of generation is 83%; if the size threshold is increased to 300 MW, the
intermediate/baseload percentage of generation is also 83%; and if both changes are made the intermediate/baseload
percentage of generation is 81%.

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nation’s electricity. By 2007 the oil-fired share was less than 2%.9 Significant construction of new
oil-fired plants is not expected.
The report also does not cover combined heat and power (CHP) plants. These are typically
industrial plants that co-produce electricity and steam for internal use and for sale. Unlike plants
that generate power exclusively to put electricity on the grid, CHP facilities have unique, plantspecific operating modes and cost structures, and economics fundamentally different from utility
scale generation. CHP generation is a small part of the electric power industry, accounting for
about 3.7% of total electricity output in 2007.10 Hydropower is excluded because no significant
construction of new, large hydroelectric plants is expected (due to environmental concerns and
the small number of available sites).11
The cost analysis is for plants entering service on January 1, 2015, which means construction
would start soon (between 2009 and 2013 depending on the technology). The plants therefore
incorporate only small projected changes from 2008 cost and performance for mature
technologies, and reflect current estimates of cost and performance for new or evolving
technologies (such as advanced nuclear power and coal gasification).
The technologies covered in the report are described briefly below. Process diagrams and images
of each technology are in Appendix A.

Supercritical Pulverized Coal
Pulverized coal plants account for the great majority of existing and planned coal-fired generating
capacity. In this system coal is ground to fine power and injected with air into a boiler where it
ignites. Combustion heat is absorbed by water-carrying tubes embedded in the boiler walls and
downstream of the boiler. The heat turns the water to steam, which is used to rotate a turbine and
produce electricity. Since about 2000 most plans for new pulverized coal plants have been for
“supercritical” designs that gain efficiency by operating at very high steam temperatures and
pressures.
In 2007, coal generation of all types12 accounted for 49% of total power generation in the United
States (see Figure 2).

9
Generation from petroleum products dropped from 365.1 billion kilowatt-hours (kWh) in 1978 to 65.7 billion kWh in
2007. Almost a quarter of the 2007 petroleum generation came not from liquid fuels, such as distillate fuel oil, but from
a solid refinery waste product, petroleum coke. EIA, Annual Energy Review 2006, Table 8.2a, and Electric Power
Monthly, March 2008, Table ES1.B.
10
In 2007 total generation was 4,160 million Mwh. Generation from the industrial and commercial sectors totaled 154
million Mwh, some of which was from non-CHP industrial and commercial generators. EIA, Annual Energy Review
2007, Table 8.1.
11
North American Electric Reliability Corp., 2008 Long-Term Reliability Assessment, October 2008, p. 46.
12
The primary alternative to pulverized coal technology for new coal plants is the circulating fluidized bed (CFB)
boiler. CFB is a commercial system used mainly for relatively small scale plants (about 250 MW and less) that burn
waste products (such as petroleum coke, a refinery residue) as well as coal. CFB is currently a niche technology and is
not covered further in this report. For additional information see Steve Blankinship, “CFB: Technology of the Future?,”
Power Engineering, February 2008. (The article is available online by searching at http://pepei.pennnet.com/).

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Figure 2.Total U.S. Electric Power Generation by Energy Source, 2007

Sources: EIA, Electric Power Monthly March 2008, Table ES1.B, and the EIA906/923 preliminary data file for 2007.

Integrated Gasification Combined Cycle (IGCC)
In this process coal is converted to a “synthesis gas” (syngas) before combustion. IGCC plants are
more expensive to build than pulverized coal generation, but proponents believe they have
compensating advantages, including:
•

Lower emissions of air pollutants, such as sulfur dioxide (SO2), nitrogen oxides
(NOx), and mercury. However, modern pulverized coal plants also have low
emissions of air pollutants, so the advantage of IGCC plants over conventional
technology is limited.

•

Greater efficiency (i.e., a lower heat rate), although with current technology
IGCC has only a small efficiency advantage over conventional coal plants.13

•

The syngas that results from the gasification process can be processed to convert
the carbon in the gas into a concentrated stream of carbon dioxide (CO2). The
syngas can then be processed, before it is burned, to remove the CO2.

In principle this pre-combustion capture of CO2 can be accomplished more easily and cheaply
than post-combustion removal of CO2 from the exhaust gases (“flue gas”) emitted by a

13

EIA estimates a heat rate advantage of 4.7% for current technology. With projected improvements the difference
widens substantially, to almost 15%. EIA, Assumptions to the Annual Energy Outlook 2008, Table 38. Another study is
less optimistic, finding that IGCC “electricity generating efficiencies demonstrated to date do not live up to earlier
projections due to the many engineering design compromises that have been made to achieve acceptable operability
and cost. The current IGCC units have and next-generation IGCC units are expected to have electricity generating
efficiencies that are less than [i.e., worse than] or comparable to those of supercritical P[ulverized] C[oal] generating
units.” Massachusetts Institute of Technology (MIT), The Future of Coal, 2007, p. 124.

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conventional coal plant. The promise of more efficient carbon capture is one of the primary
rationales for IGCC technology.
Coal-fired IGCC experience in the United States is limited to a handful of research and prototype
plants, none of which is designed for carbon capture. A commercial IGCC plant is being
constructed by Duke Energy at its Edwardsport site in Indiana, and other projects have been
proposed. However, some other power plant developers will not build IGCC plants because of
concerns over cost and the reliability of the technology.14 In general, the cost and operational
advantages of IGCC over conventional coal technology and the commercial readiness of IGCC
technology are disputed.15

Natural Gas Combined Cycle
Combined cycle plants are built around one or more combustion turbines, essentially the same
technology used in jet engines. The combustion turbine is fired by natural gas to rotate a turbine
and produce electricity. The hot exhaust gases from the combustion turbine are captured and used
to produce steam, which drives another generator to produce more electricity. By converting the
waste heat from the combustion turbine into useful electricity the combined cycle achieves very
high efficiencies, with heat rates below 7,000 btus per kWh (compared to around 9,000 btus per
kWh for new pulverized coal plants). This high efficiency partly compensates for the high cost of
the natural gas used in these plants.
Modern combined cycle plants, which evolved in the 1990s, have a relatively low construction
cost and modest environmental impacts; can be used to meet baseload, intermediate, and peaking
demand; can be built quickly; and are very efficient. Because of these advantages, since 1995
natural gas combined cycle plants have accounted for 88% of the all the new generating capacity
built in the United States capable of baseload and intermediate service. 16
Natural gas combined cycle plants and other types of gas-fired power plants are expected to
continue to dominate capacity additions into the next decade. 17 According to EIA, combined cycle
14

For instance, LS Power, a coal project developer, describes IGCC technology as “experimental.” Steve Raabe,
“‘Clean Coal’ Plant Setbacks Mount in U.S.,” The Denver Post, November 1, 2007.
15
For example, Appalachian Power (APCo, a subsidiary of the large utility American Electric Power) has proposed
building an IGCC plant to serve customers in Virginia and West Virginia. The Virginia State Corporation Commission
rejected the proposal, citing the technical immaturity and uncertain costs of IGCC technology. The same project was
approved by the West Virginia Public Service Commission, which concluded that “the Project is an efficient and
capable proposal to meet the baseload needs of APCo’s customers” and is the “best option” available to APCo.
(Virginia State Corporation Commission, Application of Appalachian Power Co., Case No. PUE-2007-0068, Final
Order, April 14, 2008, pp. 12-13; West Virginia Public Service Commission, Application for a Certificate of Public
Convenience and Necessity, Case No. 06-0033-E-CN, Commission Order, March 6, 2008, p. 25.)
16
According to the 2006 version of the EIA-860 data file of generating units, between 1995 and 2006, inclusive,
255,980 MW of new generating capacity of all types entered service. Out of this total, 168,800 MW used generating
technologies suitable for baseload and intermediate service, including geothermal, combined cycle, fuel cell,
hydroelectric, steam turbines using combustible fossil or renewable fuels, and wind turbines. Of this
baseload/intermediate segment, 148,119 MW was gas-fired combined cycles, or 88%. The next largest shares were
wind power (6%) and coal (4%).
17
EIA, Annual Energy Outlook 2008, p. 68; Matthew Wald, “Utilities Turn From Coal to Gas, Raising Risk of Price
Increases,” The New York Times, February 5, 2008; “FERC’s Moeler Just Wants to Make it Clear: Natural Gas ‘Fuel of
Choice’ in the Near Future,” Platts Electric Utility Week, October 22, 2007; Alexander Duncan, “Power Needs,
Climate Concerns to Spark ‘Bullish’ Natural Gas Market: Experts,” Platts Inside Energy, October 8, 2007.

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plants will account for 29% of all capacity additions between 2008 and 2015.18 However, this
forecast may understate actual combined cycle plant additions. The EIA estimates that coal plants
will account for almost a quarter of new capacity built through 2015, the equivalent of about 170
new coal-fired generating units.19 It is questionable whether this much coal capacity will actually
be built because of public opposition to new coal plants and the cost of the plants. Utilities
reportedly canceled 16,577 MW of planned generating capacity in 2007, of which 84% was coalfired.20 According to a Department of Energy (DOE) report, only 12% (4,500 MW) of the coal
capacity planned in 2002 to be built by 2007 was actually constructed. The report notes that
“delays and cancellations have been attributed to regulatory uncertainty (regarding climate
change) or strained project economics due to escalating costs in the industry.”21
If less coal capacity is built than planned, the main replacement is likely to be combined cycle
plants, the type of gas-fired unit capable of replacing a baseload coal plant. For example, in 2007,
power generators in Florida planned to install 4,627 MW of new coal fired capacity through
2016. By 2008 the plans for new coal-fired capacity had dropped to 738 MW, primarily “due to
environmental concerns at the State level. The majority of this decrease in planned coal-fired
generation was replaced with gas-fired units.”22
Natural gas combined cycle plants accounted for 17% of total generation in 2007,23 and natural
gas plants of all types accounted for 21% of total power generation in the United States (Figure
2).

Nuclear Power
Nuclear power plants use the heat produced by nuclear fission to produce steam. The steam drives
a turbine to generate electricity. Nuclear plants are characterized by high investment costs but low
variable operating costs, including low fuel expense. Because of the low variable costs and design
factors, nuclear plants in the United States operate exclusively as baseload plants and are
typically the first plants in a power system’s dispatch order. Nuclear power supplied 19% of the
nation’s electricity in 2007 (Figure 2).
This report discusses projected costs for Generation III/III+ technology nuclear plants. These
plants are more advanced versions of the 104 reactors currently operating in the United States,
and all reactors currently proposed for construction in the United States are Generation III/III+
designs. Compared to existing reactors, the Gen III/III+ plants are designed to reduce costs and
enhance safety through, for example, reduced complexity, standardized designs, and improved
construction techniques. Some designs also incorporate passive safety systems that are supposed
to be capable of preventing a catastrophic accident even without operator action.
18
Calculated from the Annual Energy Outlook 2008 output spreadsheet. EIA projects that natural gas-fired combined
cycle plants plus natural gas combustion turbine peaking plants will account for 54% of capacity additions through
2015.
19
Ibid. EIA projects the construction of 85,300 MW of new coal fired capacity.
20
Rebecca Smith, “Banks Hope to Expand Carbon Rules to Public Utilities,” The Wall Street Journal, March 20, 2008.
21
DOE/NETL, Tracking New Coal-Fired Power Plants, June 2008, p. 5. This report is periodically updated and posted
at http://www.netl.doe.gov/coal/refshelf/ncp.pdf.
22
North American Electric Reliability Corp., 2008 Long-Term Reliability Assessment, October 2008, p. 88.
23
According to the EIA-906/920 data file for 2007, gas-fired combined cycles accounted for 688 million megawatthours of generation, out of a total of 4,160 million megawatt-hours.

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There are several competing Gen III/III+ designs,24 but only one design has been built (General
Electric’s Advanced Boiling Water Reactor, of which four units have been constructed in Japan).
Plants based on other Gen III/III+ designs are under construction in France, Finland, and China.
As discussed later in the report, the costs of building a new nuclear plant in the United States will
apparently be very high.

Geothermal Power
Geothermal plants have operated for many years in the western United States, mainly in
California. In a typical binary cycle geothermal facility, wells draw hot water and steam from
underground into a heat exchanger. In the heat exchanger a working fluid is vaporized and used to
drive a turbine generator (the underground steam is not used directly because it contains corrosive
impurities and can release air pollutants). In geothermal fields that have been depleted by years of
use, such as the Geysers field in California, operators can inject water into the layers of hot rock
to supplement the naturally available water and boost steam production. Unlike solar and wind
power, which are weather-dependent, geothermal plants operate as dispatchable baseload plants.
However, with current technology, geothermal plants are limited to small facilities (typically
under 50 MW) at sites in the western United States.25 In 2007, geothermal plants produced 0.4%
of the nation’s power supply (Figure 2).26

Wind Power
Wind power plants (sometimes referred to as wind farms) use wind-driven turbines to generate
electricity. An individual turbine typically has a capacity in the range of 1.5 to 2.5 MW, and a
wind plant installs dozens or hundreds of these turbines. As noted above, wind is a variable
renewable resource because its availability depends on the vagaries of the weather. Wind supplied
1% of total U.S. power supply in 2007 (Figure 2); EIA estimates that assuming no changes to
current law and regulation, this will increase to 2.4% by 2030.27

Solar Thermal and Solar Photovoltaic (PV) Power
Solar thermal and PV power are alternative means of harnessing sunlight to produce electricity.
PV power uses solar cells to directly convert sunlight to electricity. To date most of the solar PV
installations in the United States have been small (about one MW or less). Two exceptions are the
installations at Nellis Air Force Base in Nevada (14 MW) and the Alamosa Photovoltaic Power
Plant in Colorado (8 MW).
24

For an illustrated summary of several of the Gen III/III+ designs, see “UK Nuclear Power: The Contenders,” BBC
News, January 10, 2008 http://news.bbc.co.uk/2/hi/science/nature/5165182.stm. Additional information is available
from the links at http://www.nei.org/keyissues/newnuclearplants/newreactordesigns/.
25
As of August 2008, a reported 95 geothermal projects with publicly known generating capacities were in
development in the United States. The upper estimate of the total capacity of these projects was 3,959.7 MW, or an
average of 42 MW per project. All the projects are located in western states except for a single 1 MW project in
Florida. Kara Slack, U.S. Geothermal Power Production and Development Update, Geothermal Energy Association,
August 2008, p. 8.
26
For additional information on geothermal power see Steve Blankinship, “What Lies Beneath,” Power Engineering,
January 2007, available by searching http://pepei.pennnet.com/).
27
EIA, Annual Energy Outlook 2008, p. 70. For more detail on wind power, see CRS Report RL34546, Wind Power in
the United States: Technology, Economic, and Policy Issues, by (name redacted) and (name redacted).

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Solar thermal plants, also referred to as concentrated solar power (CSP), concentrate sunlight to
heat a working liquid to produce steam that drives a power-generating turbine. Two major types
of solar thermal systems are parabolic trough and power tower technologies. Parabolic trough
plants use an array of mirrors to focus sunlight on liquid-carrying tubes integrated with the
mirrors. Several parabolic trough installations have operated successfully in California since the
1980s, and the 64 MW Nevada Solar One plant began operating in 2007.
The power tower technology uses a mirror field to focus sunlight on a central tower, where the
heat is used to produce steam for power generation. A research power tower, the Solar One/Two
plant, operated for several years in the 1980s and 1990s in California. A power tower plant has
recently been constructed in Spain and a 400 MW project has been proposed for California.
Several new solar thermal projects, primarily of the parabolic trough and related types, are in
development. The capacity of these projects range up to 554 MW. A potential advantage of solar
thermal systems is the ability to produce electricity when sunlight is weak or unavailable by
storing solar heat in the form of molten salt. If storage proves economical for large-scale plants,
then solar thermal facilities in regions with strong, near continuous daytime sunlight, such as the
Mojave desert, could be operated as dispatchable plants with firm capacity.
In 2007, solar thermal generation accounted for 0.01% of total generation, and solar PV power for
less (Figure 2).

Factors that Drive Power Plant Costs
This section of the report discusses the major factors that determine the costs of building and
operating power plants. These factors include:
•

Government incentives.

•

Capital (investment) cost, including construction costs and financing.

•

Fuel costs.

•

Air emissions controls for coal and natural gas plants.

Government Incentives
Many government incentives influence the cost of generating electricity. In some cases the
incentives have a direct and clear influence on the cost of building or operating a power plant,
such as the renewable investment tax credit. Other programs have less direct affects that are
difficult to measure, such as parts of the tax code that influence the cost of producing fossil fuel.28
The economic analysis in this report incorporates the following incentives that directly affect the
cost of building or operating power plants.29
28

For a comprehensive list of energy market incentives, see EIA, Federal Financial Interventions and Subsidies in
Energy Markets 2007, April 2008.
29
The analysis does not include the credit for carbon dioxide sequestration established by P.L. 110-343, Division B,
Title I, Subtitle B, Section 115 (adding a new §45Q to 26 U.S.C.). The law provides for tax credits of $20 per metric
(continued...)

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Renewable Energy Production Tax Credit30
The credit has a 2008 value of 2.0 cents per kWh, with the value indexed to inflation. The credit
applies to the first 10 years of a plant’s operation. As of October 2008 the credit is available to
plants that enter service before the end of 2009. The credit is currently available to new wind,
geothermal, and several other renewable energy sources. New solar energy projects do not
qualify, and geothermal projects can take the production tax credit only if they do not use the
renewable investment tax credit (discussed below).

Nuclear energy production tax credit31
The credit, which is for new advanced nuclear plants, has a nominal value of 1.8 cents per kWh.
The credit applies to the first eight years of plant operation. Unlike the renewable production tax
credit the nuclear credit is not indexed to inflation and therefore drops in real value over time.
This credit is subject to several limitations:
•

It is available to advanced (i.e., Gen III/III+) nuclear plants that begin
construction before January 1, 2014, and enter service before January 1, 2021.

•

For each project the annual credit is limited to $125 million per thousand
megawatts of generating capacity.

•

The full amount of the credit will be available to qualifying facilities only if the
total capacity of the qualifying facilities is 6,000 megawatts or less. If the total
qualifying capacity exceeds 6,000 megawatts the amount of the credit available
to each plant will be prorated. EIA estimates in its 2008 Annual Energy Outlook
that 8,000 megawatts of new nuclear capacity will qualify;32 in this case the
credit amount would drop to 1.35 cents per kWh once all the qualifying plants
are on-line. This pro-rated value is used in the report’s economic analysis of
generating costs.

Loan Guarantees for Nuclear and Other Carbon-Control Technologies33
Under final Department of Energy (DOE) rules the loan guarantees can cover up to 80% of the
cost of a project, and are awarded based on a detailed evaluation of each applicant project.
Entities receiving loan guarantees must make a “credit subsidy cost” payment to the federal
(...continued)
ton of CO2 sequestered and $10 per metric ton for CO2 captured and used for enhanced oil recovery. The credit is in
effect through the year in which the cumulative volume of CO2 captured totals 75 million metric tons. This credit is
excluded because it is very difficult to predict how long the credit will be in effect. The EIA analysis of the LiebermanWarner Climate Security Act of 2009 (S. 2191) estimates, for the cases that project carbon capture, cumulative CO2
capture of about 80 million to 100 million tons by 2014, which is prior to the on-line data of 2015 assumed for new
power plants in this study. (For the spreadsheets which contain the detailed S. 2191 outputs, see the EIA website at
http://www.eia.doe.gov/oiaf/servicerpt/s2191/index.html.)
30
26 U.S.C. §45, as amended by P.L. 110-343, Division B, Title I, Subtitle A, Section 101(a).
31
26 U.S.C. §45J.
32
For a discussion of the operation of the credit see EIA, Annual Energy Outlook 2007, p. 21. For the forecast of 8,000
MW of nuclear capacity on-line before 2021, see the Annual Energy Outlook 2008, p. 70.
33
10 CFR § 609 (RIN 1901-AB21), October 4, 2007 http://www.lgprogram.energy.gov/keydocs.html.

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treasury that reflects the anticipated cost of the guarantee to the government, including a
probability weighted cost of default. Because the debt is backed by the federal government, it is
expected to carry the highest credit rating and therefore a low interest rate.34 The guarantees are
unavailable to publicly owned utilities, such as municipal systems.35
Congress periodically determines the total value of the guarantees that the DOE is authorized to
grant. In April 2008, the Department of Energy announced plans to solicit up to $18.5 billion in
loan guarantee applications for nuclear projects.36 As of November 2008, DOE was considering
several applications for loan guarantees.
Developers and investors have stated that the loan guarantees are critical to constructing at least
the first wave of new nuclear plants. This is because of the multi-billion dollar cost of a nuclear
project, which can exceed the total market value of the company building a plant. For example, in
2008 the president of Exelon Generation, which operates a large fleet of existing nuclear plants
and plans to build new units, stated that constructing new nuclear plants would be “impossible”
without loan guarantees.37

Energy Investment Tax Credit38
Tax credits under this program are available to solar and geothermal electricity generation, and
some other innovative energy technologies. Wind energy systems do not qualify. The credit is
10% for geothermal systems, and is 30% for solar electric systems installed before January 1,
2017 (after which it reverts to 10%). Geothermal projects that take the investment tax credit
cannot claim the renewable production tax credit.39 The depreciable basis of the project for tax
purposes is reduced by 50% of the credit value. The investment tax credit is available to

34
On the assumption that the guaranteed debt would have a high (AAA) rating, see “Loan Guarantees for Projects that
Employ Innovative Technologies,” 10 CFR § 609 (RIN 1901-AB21), October 4, 2007, p. 24.
35
Entities receiving loan guarantees must make a substantial equity contribution to the project’s financing. Public
power entities normally do not have the retained earnings needed to make such payments. The rules also preclude
granting a loan guarantee if the federal guarantee would cause what would otherwise be tax exempt debt to become
subject to income taxes. Under current law this situation would arise if the federal government were to guarantee public
power debt. For further information on these and other aspects of the loan guarantee program see U.S. DOE, final rule,
“Loan Guarantees for Projects that Employ Innovative Technologies,” 10 CFR § 609 (RIN 1901-AB21), October 4,
2007 http://www.lgprogram.energy.gov/keydocs.html.
36
DOE Announces Plans for Future Loan Guarantee Solicitations, Department of Energy press release, April 11, 2008.
According to press reports, the Japanese and French governments may also offer loan guarantees to American nuclear
projects. French and Japanese companies are expected to be major suppliers to new U.S. nuclear projects. The terms of
the loan guarantees, assuming they come to fruition, are unknown. Elaine Hiruo, “Japanese Government Considers
Loan Guarantees for U.S. Reactors,” Platts Nucleonics Week, August 14, 2008, and Elaine Hiruo, “Japan Clears Way
for Loan Guarantees in US,” Platts Nucleonics Week, September 25, 2008.
37
Steven Dolley, “Nuclear Power Key to Exelon’s Low-Carbon Plan,” Platts Nucleonics Week (February 14, 2008).
For similar comments see “House Appropriators Seek DOE Loan Guarantees Delay Pending GAO Review,”
EnergyWashington.com, June 10, 2008; Dr. Joe C. Turnage, UniStar Nuclear, presentation to the California Energy
Commission, “New Nuclear Development: Part of the Path Toward a Lower Carbon Energy Future,” June 28, 2007;
and Selina Williams, “US Government Loan Guarantees For New Nuclear Too Small NRC,” CNNMoney.com, March
10, 2008.
38
26 U.S.C. §48, as amended by P.L. 110-343, Division B, Title I, Subtitle A, Section 103(a)(1).
39
For additional information see the discussion of the investment tax credit in the federal incentives section of the
Database of State Incentives for Renewable Energy website http://www.dsireusa.org/.

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independent power producers and investor owned utilities, but is inapplicable to tax-exempt
publicly owned utilities.40

Clean Coal Technologies Investment Tax Credit41
This tax credit can be used by investor owned utilities or independent power producers (it is
inapplicable to tax-exempt publicly owned utilities). It is limited to a total of $2.55 billion in tax
credits, of which (1) $0.8 billion is specifically for IGCC plants; (2) $0.5 billion is for non-IGCC
advanced coal technologies, and (3) $1.25 billion is for advanced coal projects generally. The tax
credits in the third category will not be awarded until after the program that encompasses the first
two categories of tax credits is completed or until such other date designated by the Secretary of
Energy.42 The depreciable basis of a project for tax purposes is reduced by 50% of the credit
value.

State and Local Incentives
State and local governments can offer additional incentives, such as property tax deferrals. The
combined value of the government tax breaks can run into the hundreds of millions of dollars per
project. For example, Duke Energy’s Edwardsport IGCC project in Indiana is expected to receive
almost half-a-billion dollars in federal, state, and local tax incentives. 43
State utility commissions can use rate treatment of new plants as a financial incentive for the
investor owned utilities they regulate. Under traditional rate making a utility is not permitted to
earn a return on its construction investment until a plant is in service. This approach to
ratemaking is used to motivate the utility to prudently manage construction, and to ensure that
customers do not have to pay for a power plant until it is operating. However, if a project is very
expensive, the time lag between when costs are incurred and when return on the investment is
allowed in rates can put a financial strain on the company. If the plant is expensive, adding the
return into rates as a single big adjustment can inflict “rate shock” on customers.
For these reasons, utilities sometimes argue for an alternative rate making method called
“construction work in progress (CWIP) in rates.” In this approach, a utility is allowed to recover
in rates the return on its investment as the plant is being built. CWIP in rates relieves the utility of
the financial strain of carrying an expensive investment that is yielding no income, phases-in the
rate increase to customers, and decreases the utility’s financial exposure if the project is delayed.
On the other hand, the pressures for prudent construction management inherent in traditional
ratemaking are dampened.

40
Investor owned utilities did not qualify for this credit until the passage of P.L. 110-343 in October 2008. See P.L.
110-343, Division B, Title I, Subtitle A, Sections 103(e) and 103(f)(4).
41
26 U.S.C. §48A, as amended by P.L. 110-343, Division B, Title I, Subtitle B, Section 111.
42

The IGCC credit is 20% capped at $133.5 million per project, with a requirement that the credits be allocated to
projects in each of three categories: Bituminous coal-fired, subbituminous coal-fired, and lignite-fired plants. Other
advanced coal technologies can qualify for a 15% credit (with a cap of $125 million per project) if 1) a new unit can
achieve a heat rate of 8,530 btus/kWh or less and near zero non-CO2 emissions, or 2) an existing plant can meet various
criteria for improving thermal efficiency, including by replacing inefficient old units at a plant site with new units.
43
“Consumers Energy Latest to Win Tax Concessions,” Platts Electric Power Daily, November 29, 2007.

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Some states, such as South Carolina and Mississippi, have passed legislation allowing utility
projects that meet certain criteria to receive CWIP in rates.44 In other cases utilities have received
CWIP in rates under existing rules. CWIP in rates has expanded beyond its historic application to
very expensive coal and nuclear projects. For example, the Kansas and Wisconsin commissions
have allowed CWIP in rates for relatively small wind projects.45

Capital and Financing Costs
Construction Cost Components and Trends
Most of the generating technologies discussed in this report are capital intensive; that is, they
require a large initial construction investment relative to the amount of generating capacity built.
Power plant capital costs are often discussed in terms of dollars per kilowatt (kW) of generating
capacity. All of the technologies considered in this report have estimated 2008 costs of $2,100 per
kW or greater, with the exception of the natural gas combined cycle plant ($1,200 see Appendix
B). Nuclear, geothermal, and IGCC plants have estimated costs in excess of $3,000 per kW.
Power plant capital costs have several components. Published information on plant costs often do
not clearly distinguish which components are included in an estimate, or different analysts may
use different definitions. The capital cost components are:
•

Engineering, Procurement, and Construction (EPC) cost: this is the cost of the
primary contract for building the plant. It includes the cost of designing the
facility, buying the equipment and materials, and construction.46

•

Owner’s costs: these are any construction costs that the owner handles outside
the EPC contract. This could include arranging for the construction of
transmission and fuel delivery facilities (such as a natural gas pipeline) to a
power plant.

•

Capitalized financing charges: a plant developer incurs financing charges while a
power plant is being built. This includes interest on debt and an imputed cost of
equity capital. Until the plant is operating these costs are capitalized; that is,

44
Mary Powers, “Governor Expected to Sign Mississippi Bill on Collecting Costs of Building Baseload,” Platts
Electric Utility Week, April 21, 2008; Elaine Hiruo and Tom Harrison, “Summer Owners Lock in Price, Schedule for
Planned New Reactors,” Platts Nucleonics Week, May 29, 2008. In addition, Florida, Louisiana, Virginia, and North
Carolina will reportedly allow return on CWIP for nuclear plants (Dr. Joe C. Turnage, UniStar Nuclear, “New Nuclear
Development: Part of the Strategy for a Lower Carbon Energy Future,” presentation to the Center for Strategic and
International Studies meeting “Evaluating the Business Case for Nuclear Power,” July 31, 2008, p. 4). The treatment of
CWIP in rates varies by jurisdiction and by case. The amount of CWIP allowed is typically updated periodically and
may be limited by a total project cost approved by the commission.
45
Wisconsin Public Service Commission, Certificate and Order, Docket 6680-CE-171, May 10, 2007 (for Wisconsin
Power & Light’s Cedar Ridge project, estimated to cost $179 million); Kansas State Corporation Commission, Final
Order, Docket 08-WSEE-309-PRE, December 27, 2007 (for Westar Energy’s investment in the Central Plains and Flat
Ridge wind projects, estimated to cost the utility $282 million).
46
Typical practice is for the project developer to enter into a single EPC contract with a large construction and
engineering firm. The firm is responsible for most plant construction activities and absorbs significant cost, delay, and
technical risk, which is reflected in the contract price. A developer can act as its own EPC manager and avoid paying
the risk premium to a third party contractor, but in this case the developer absorbs the price and performance risks.

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become part of the investment cost of the project for tax, regulatory, and financial
analysis purposes (see further discussion of financing costs, below).
Construction costs for power plants have escalated at an extraordinary rate since the beginning of
this decade. According to one analysis, the cost of building a power plant increased by 131%
between 2000 and 2008 (or by 82% if nuclear plants are excluded from the estimate). Costs
reportedly increased by 69% just since 2005. The cost increases affected all types of generation.
For example, between 2000 and 2008, the cost of wind capacity reportedly increased by 108%,
coal increased by 78%, and gas-fired plants by 92%.47 The cost increases have been attributed to
many factors, including:
•

High prices for raw and semi-finished materials, such as iron ore, steel, and
cement.

•

Strong worldwide demand for generating equipment. China, for example, is
reportedly building an average of about one coal-fired generating station a
week. 48

•

Low value of the dollar.

•

Rising construction labor costs, and a shortage of skilled and experienced
engineering staff.49

•

An atrophied domestic and international industrial and specialized labor base for
nuclear plant construction and components.

•

In the case of wind, competition for the best plant sites and a tight market for
wind turbines; in the case of nuclear plants, limited global capacity to produce
large and ultra-large forgings for reactor pressure vessels.50

•

Coincident worldwide demand for similar resources from other business sectors,
including general construction and the construction of process plants such as
refineries. Much of the demand is driven by the rapidly growing economies of
Asia.51

The future trend in construction costs is a critical question for the power industry. Continued
increases in capital costs would favor building natural gas plants, which have lower capital costs
than most alternatives. Stable or declining construction costs would improve the economics of
capital-intensive generating technologies, such as nuclear power and wind. 52 At least some long47

IHS CERA press release, “Construction Costs for New Power Plants Continue to Escalate IHS-CERA Power Capital
Costs Index,” May 27, 2008 http://energy.ihs.com/News/Press-Releases/2008/IHS-CERA-Power-Capital-CostsIndex.htm.
48
Keith Bradsher and David Barboza, “Pollution From Chinese Coal Casts a Global Shadow,” The New York Times,
June 11, 2006.
49
Christopher D. Kirkpatrick, “A Bidding War for Engineers: Power Plant Construction Boom Creates a Labor
Shortage,” The Charlotte (North Carolina) Observer, September 5, 2008.
50
Yuliya Chernova, “Change in the Air,” The Wall Street Journal, February 11, 2008; Bert Caldwell, “BPA’s wind
power tops 1,000 megawatts,” The (Spokane, Washington) Spokesman-Review, January 12, 2008; Yoshifumi Takemoto
and Alan Katz, “Samurai-Sword Maker’s Reactor Monopoly May Cool Nuclear Revival,” Bloomberg.com, March 13,
2008.
51
Matthew L. Wald, “Costs Surge For Building Power Plants,” The New York Times, July 10, 2007.
52
Wind power is less costly to build than, for example, coal or nuclear plants. However, because wind plants are
weather dependent, wind plants have much lower capacity factors than coal or nuclear plants. A typical wind plant
(continued...)

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term moderation in cost escalation is likely, as demand growth slackens and new supply capacity
is added. 53 But when and to what degree cost increases will moderate is as unpredictable as the
recent cost escalation was unforeseen.

Financing Power Plant Projects
Even relatively small power plants cost millions of dollars. For example, the capital cost for a 50
MW wind plant would be about $105 million at $2,100 per kW of capacity. The investment cost
is typically financed by a combination of debt and equity.54 The financing structure and the cost
of money depends on the type of developer and project-specific risk.
Three types of entities typically develop power plants:
•

Investor-owned utilities (IOUs): IOUs are owned by private investors and are
subject to government regulation of rates and conditions of service. They have
guaranteed service territories and face limited competition. State utility
commissions set electric rates designed to maintain the financial health of the
utility, assuming it operates prudently. The commission also must approve
proposals by the utility to build new power plants.55

•

Publicly-owned utilities (POUs): A POU is a utility that is an agency of a
municipality, a state, or the federal government. Electric cooperatives are also
considered to be POUs. Like IOUs, POUs have guaranteed service territories and
face limited competition. Most POUs are small, provide only distribution service,
and have limited financial and management resources.56 But larger and some
smaller POUs also own and operate power plants, sometimes as co-owners of
projects where an IOU or independent power producer is the lead developer.
Examples of POUs with large amounts of generation include the Tennessee
Valley Authority and the municipal utilities serving the cities of Los Angeles and

(...continued)
capacity factor is about 34%, compared to 70% to over 90% for coal and nuclear plants. This means the capital costs of
a wind plant are spread over relatively few megawatt-hours of generation, increasing the cost per unit of electricity
sold. In the case of variable renewable resources like wind and solar power, anything that reduces capital costs or
increases utilization can significantly improve plant economics.
53
For example, vendors in Asia and Europe are planning to add new capacity to manufacture very large forgings,
particularly important for nuclear plants. Mark Hibbs, “Chinese Equipment Fabricators Set Ambitious Capacity
Targets,” Platts Nucleonics Week, May 22, 2008; Pearl Marshall, “UK’s Sheffield Forgemasters Plans to Produce
Ultra-large Forgings,” Platts Nucleonics Week, April 3, 2008.
54
Equity capital includes the funds provided by the owners of the firm (i.e., the stockholders). Debt is borrowed
money. The owners of a project seek to repay debt, and to both recover their equity investment and earn a return on that
investment.
55
Prior to the restructuring of the electric power industry that began in the 1990s, IOUs were typically vertically
integrated, providing generation, transmission, and distribution (final delivery of electricity to consumers) in a statesanctioned monopoly service area. With restructuring, some states required or encouraged utilities to divest their power
plants. In many parts of the country control (though not ownership) of transmission assets is now in the hands of
federally sponsored regional transmission organizations (RTOs). Some states that required IOUs to divest generation
are now allowing utilities to once again own and operate power plants, such as California.
56
In 2006, out of 2,010 government-owned electric utilities, only 98 had total revenues in excess of $100 million
dollars. In contrast, the fuel cost for a single large power plant can exceed $100 million per year. American Public
Power Association, 2008-09 Annual Directory and Statistical Report, p. 30 (data does not include electric
cooperatives).

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San Antonio. POUs set their own rates and make their own decisions to build
power plants.
•

Independent Power Producers (IPPs): IPPs are merchant developers and
operators of power plants that sell wholesale power to utility and industrial
buyers. Within limits they can sell power at whatever price the market will bear.57
IPPs face more financial risk than regulated utilities—they do not have
guaranteed service territories and can face intense competition for power sales—
but can also earn larger profits. IPPs make their own decisions to build power
plants.

All three types of entities play a major role in the electric power industry (Table 1). The lines
between the entities can blur. Holding companies that own IOUs can also own IPPs. POUs
sometimes own large shares of power projects developed by IOU or IPPs.
Table 1. Shares of Total National Electric Generation and Generating Capacity, 2006
Generation

Generating Capacity

Publicly-Owned Utilities

22%

21%

Investor-Owned Utilities

41%

38%

Non-Utilities

37%

41%

National Total

100%

100%

Source: American Public Power Association http://www.appanet.org/files/PDFs/nameplate2006.pdf, citing Energy
Information Administration.
Notes: Non-utility generation includes independent power producers and power marketers. Non-utility
capacity includes industrial and commercial facilities. Capacity shares are for nameplate capacity.

The cost of the money used to finance power projects varies significantly between IOU, POUs,
and IPPs. A POU will normally finance a project with 100% debt at a low interest rate. The rate is
low because interest paid on public debt is exempt from federal or state income taxes, 58 and
because public entities have a very low risk of default (failure to make debt payments), much
lower than for private businesses. 59 Typical municipal bonds have ratings in the middle or upper
tiers of investment grade debt.60
57
In some parts of the country RTOs operate power markets and have capped spot electricity prices, such as at $1,000
per Mwh, to prevent extraordinary price spikes. These caps apply to spot sales of electricity, not to bilateral contracts.
58
Because the debt is tax free, the POU can pay the bond holder a lower interest rate than taxable debt must offer. The
bond holder accepts the lower POU tax-free interest rate since, other things being equal, its after-tax return is the same.
59
Moody’s Investors Service, Mapping of Moody’s U.S. Municipal Bond Rating Scale to Moody’s Corporate Rating
Scale and Assignment of Corporate Equivalent Ratings to Municipal Obligations, June 2006, p.2. According to
Moody’s, between 1970 and 2000, out of 699 rated municipal bond issues for electric power, only two defaulted
(including the Washington Public Power Supply System default on a large nuclear construction program). Over the
same period, about 70% of municipal bonds were rated A or higher, and less than 1% were rated below investment
grade. Moody’s Investors Service, Moody’s US Municipal Bond Rating Scale, November 2002, pp. 5-6.
60
Moody’s Investors Service, Moody’s US Municipal Bond Rating Scale, November 2002, p. 6. Rating agencies assign
debt to credit worthiness categories. Investment grade debt has a rating of BBB- or higher in the nomenclature used by
Standard & Poors and Fitch. The equivalent category for Moody’s is Baa3 and higher. Lower rated debt is referred to
as speculative or high yield issues, or less pleasantly as “junk bonds.” For descriptions of the ratings systems and
crosswalks see Edison Electric Institute, 2007 Financial Review, p. 86, and http://www.nnnsales.com/faq/faqbuyersinvestors8.htm. Note that the municipal bond market was roiled by the 2008 financial crisis (Tom Herman,
(continued...)

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Privately owned IOUs and IPPs finance power projects with a mix of debt and equity. Debt is
more costly to these companies than to POUs because it is not tax exempt and because they
usually have lower credit ratings. The electric utility industry as a whole has a credit rating in the
lower tier of the investment grade category (BBB).61 IPP debt often falls in the speculative
category and has a higher interest rate than IOU or POU issues.62
Investors expect private developers to make a significant equity contribution to a project.63
Reliance on equity versus debt varies by company and project. The cost analysis used in this
study assumes that IPPs and IOUs rely on, respectively, 40% and 50% equity (see Table D-1),
except in the case where federal loan guarantees are available (see discussion of “Government
Incentives”, above). Equity is more expensive than debt,64 and is more expensive for IPPs than
IOUs because IPPs typically face more competition and financial risk.
In summary:
•

Because POUs can finance a power project with 100% low-cost debt they can
build power plants more cheaply than IOUs or IPPs. However, because of the
small size of most POUs they do not have the financial or management resources
to take on large and complex projects by themselves, so POUs often partner on
projects where an IOU or IPP is the lead developer.

•

IOU’s typically have lower financing costs than IPP’s because they have lower
costs of debt and equity. 65

(...continued)
“Muni Yields Rise to Rare Levels” The Wall Street Journal, November 5, 2008).
61
Roughly 70% of utility companies were rated between BBB+ and BBB- in 2007. About 10% were rated below
investment grade. Edison Electric Institute, 2007 Financial Review, pp. 81 and 87.
62
Most IPP debt is reportedly rated below investment grade (telephone conversation with Scott Solomon, Moody’s
Investors Service, February 15, 2008). For instance, in June 2008 the debt ratings for several large IPP developers were
all speculative grade: NRG (Standard & Poors B rating), AES (B+ to BB-), Edison Mission Energy (BB-), and Dynegy
(B-). (Source: Standard & Poors NetAdvantage on-line data system). IPP power plants may be project-financed; that is,
the financing and the recourse of the debt holders is tied to a specific project, not to the corporation as a whole. For
example, the LS Power Sandy Creek, AES Ironwood, and Calpine’s Riverside and Rocky Mountain projects all have
project-specific, speculative grade debt ratings. (Source: Moody’s Investors Service press releases, August 3, 2006,
August 14, 2007, and February 8, 2008.)
63
Over-reliance on debt is considered risky for private entities and leads investors to demand higher interest rates. At
some level of debt a project would be impossible to finance. POUs can rely on 100% debt financing because they
control their own rates and are backed-up by the government entity that owns or finances the utility.
64
Equity is more expensive than debt in part because interest payments on debt are tax deductible while the imputed
cost of equity is not an expense for income tax purposes. Another consideration is that in the event of bankruptcy
bondholders are paid before shareholders. An equity investment is therefore riskier than holding debt and investors
demand higher compensation. (Unlike a bond which has a known interest rate, there is no directly measurable cost of
equity. Its cost is essentially the return investors will expect on their equity stake in the firm. Various techniques are
used to estimate the cost of equity. The concepts are discussed in standard finance texts; see for example, Stewart
Myers and Richard Brealey, Principles of Corporate Finance, 7th edition, 2003, Chapter 9.)
65

Financing arrangements can be far more complex than described in this brief overview. As an illustration, see the
discussions of wind power financing in Ryan Wiser and Mark Bolinger, Annual Report on U.S. Wind Power
Installation, Cost, and Performance Trends: 2007, U.S. DOE, May 2008, p. 14; and John P. Harper, Matthew D.
Karcher, and Mark Bolinger, Wind Project Financing Structures: A Review & Comparative Analysis, Lawrence
Berkeley Laboratory, September 2007. For a description of the financing arrangements for an IPP-developed coal plant,
see the discussion of the Plum Point project in “North American Single Asset Power Deal of the Year 2006,” Project
Finance, February 2007.

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•

Financing costs are highest for IPPs, which makes them somewhat less prone to
take on the highest cost projects (such as coal and nuclear plants) unless POUs or
IOUs are co-owners.

Fuel Costs
Fuel costs are important to the economics of coal, nuclear, and natural gas plants, and irrelevant
to solar, geothermal, and wind power. Recent trends in the delivered cost of coal and natural gas
to power plants are illustrated below in Figure 3. The constant dollar prices of both fuels have
increased since the beginning of the decade, but the price escalation has been especially severe
for natural gas.66 Natural gas has also been consistently more expensive than coal. The
comparatively low cost of coal partly compensates for the high cost of building coal plants, while
the high cost of natural gas negates part of the capital cost and efficiency advantages of combined
cycle technology.
Because it takes years to build a power plant, and plants are designed to operate for decades,
generation plans largely pivot on fuel price forecasts. However, fuel prices have been notoriously
difficult to predict. For example, EIA forecasts of delivered coal prices and natural gas wellhead
prices have been off target by an average of, respectively, 47% and 64%.67 EIA attributes the gap
between actual and forecasted gas prices to a host of factors:
As regulatory reforms that increased the role of competitive markets were implemented in
the mid-1980s, the behavior of natural gas was especially difficult to predict. The
technological improvement expectations embedded in early AEOs [Annual Energy
Outlooks] proved conservative and advances that made petroleum and natural gas less costly
to produce were missed. After natural gas curtailments that artificially constrained natural
gas use were eased in the mid-1980s, natural gas was an increasingly attractive fuel source,
particularly for electricity generation and industrial uses. Historically, natural gas price
instability was strongly influenced by natural gas resource estimates, which steadily rose,
and by the world oil price. More recently, the AEO reference case has overestimated natural
gas consumption due to the use of natural gas wellhead price projections that proved to be
significantly lower than what actually occurred.68

EIA’s analysis illustrates how the confluence of technological, regulatory, resource, and domestic
and international market factors make fuel forecasts so problematic. Fuel price uncertainty is
especially important in evaluating the economics of natural gas-fired combined cycle plants. For
the base assumptions used in this study, fuel constitutes half of the total cost of power from a new
combined cycle plant, compared to 18% for a coal plant and 6% for a nuclear plant.

66
Coal and gas prices have increased due to national and global demand growth, limited excess production capacity,
certain unusual circumstances (such as flooding that reduced Australian coal production and exports), increases in rail,
barge, and ocean-going vessel rates for delivering coal to consumers, and the run-up in world oil prices. For a
discussion of energy price trends, see EIA’s Annual Energy Outlook for long-term projections and the Short-Term
Energy Outlook for near-term forecasts http://www.eia.doe.gov/oiaf/forecasting.html.
67
EIA, Annual Energy Outlook Retrospective Review, April 2007, p. 5.
68
Ibid., pp. 2 and 3 [table citations omitted].

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Figure 3. Coal and Natural Gas Constant Dollar Price Trends

Sources: EIA, Monthly Energy Review on-line data, Table 9.10, converted to constant dollars by CRS.

The price of the uranium used to make nuclear fuel has, like coal and natural gas, increased
sharply and has been volatile (Figure 4). Although prices have recently dropped, they are still far
above historic levels.69 Over the long term, EIA expects nuclear fuel prices to increase in real
terms from $0.58 per mmbtu in 2007 to $0.77 per mmbtu in 2023, and then slowly decline.70
Even prices twice as high would not have a major impact on nuclear plant economics, which are
dominated by the capital cost of building the plant.

69
Factors that caused prices to rise include increased demand, problems bringing new uranium mines into service, and
the depletion of commercial inventories of uranium. The recent decline in prices may be due in part to an improved
short-term production outlook; see “ERI Expects Base Price to Drop, Then Rise Again,” Platts Nuclear Fuel, June 16,
2008. It takes years before a change in uranium prices is reflected in a reactor fuel load. The lag is caused by the time it
takes to process the uranium and manufacture fuel rods; multi-year contracts that do not reflect current prices; and
reactor fueling schedules (refueling takes place on 18 or 24 month cycles, and at each refueling only about a third of the
core is replaced). This lag can cut both ways: If uranium prices decline, a plant may still have reloads based on
expensive uranium in the pipeline.
70
For the EIA nuclear fuel price forecast used in the Annual Energy Outlook 2008, go to http://www.eia.doe.gov/oiaf/
aeo/electricity.html and click on “figure data” for Figure 70.

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Figure 4. Uranium Price Trends

Sources: Trade Tech Exchange Values, as reported in Platts Nuclear Fuel and http://www.uranium.info/.

Air Emissions Controls for Coal and Gas Plants
Regulations that limit air emissions from coal and natural gas plants can impose two types of
costs: The cost of installing and operating control equipment, and the cost of allowances71 that
permit plants to emit pollutants. The following emissions are discussed below:
Emissions from coal:
•

Sulfur dioxide (SO2), a precursor to acid rain and the formation in the atmosphere
of secondary particulates72 that are unhealthy to breathe and can impair visibility.

•

Mercury, a toxic heavy metal.

•

Primary particulates (soot) entrained in the power plant’s flue gas.

71

Under the existing federal SO2 and NOx regulatory programs, most existing plants have been allocated allowances
sufficient to cover their emissions. These existing plants do not need to buy emissions, and may have surplus emissions
to sell, especially if the plants have retrofitted pollution control equipment.
72
Coal plants can produce two types of particulates. Primary particulates, sometimes referred to as soot, are formed in
the combustion process. Secondary particulates form in the atmosphere through the condensation of nitrates and
sulfates. Particulates are objectionable because of visibility and health effects. For more information see Rod Truce,
Robert Crynack, and Ross Blair, “The Problem of Fine Particles,” Coal Power, September 30, 2008
http://www.coalpowermag.com/environmental/156.html.

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Emissions from coal and natural gas:
•

Nitrogen oxides (NOx), a precursor to ground level ozone, acid rain, and the
formation in the atmosphere of secondary particulates.

•

Carbon dioxide (CO2), a greenhouse gas produced by the combustion of fossil
fuels.

The regulations and control technologies for SO2, NOx, particulates, and mercury are discussed
briefly under the category of “conventional emissions.” These pollutants are subject to either
existing regulations or regulations being developed under current law, and can be controlled with
well-understood, commercially-available technologies. CO2 is discussed in more detail because
control technologies are still under development and may be far more costly than controls for
conventional emissions.73 While CO2 is not currently subject to federal regulation, control
legislation is being actively considered by the Congress and some states are taking action to limit
CO2 emissions.
More information on air emissions, particularly on regulatory and policy issues, is available in
numerous CRS reports. The reports can be accessed through the “Energy, Environment, and
Resources” link on the CRS website, http://www.crs.gov.

Conventional Emissions
The Environmental Protection Agency (EPA) has established National Ambient Air Quality
Standards (NAAQS) for several pollutants, including SO2, NOx, ozone, and particulates. New
coal and natural gas plants built in areas in compliance with a NAAQS standard must install Best
Available Control Technology (BACT) pollution control equipment that will keep emissions
sufficiently low that the area will stay in compliance. Plants built in areas not in compliance with
a NAAQS (referred to as “non-attainment” areas) must meet a tighter Lowest Achievable
Emission Rate (LAER) standard.74 In practice, air permit emissions are negotiated case-by-case
between the developer and state air authorities. Federal standards set a ceiling; state permits can
specify lower emission limits.
In addition to technology control costs, new plants that emit SO2 must buy SO2 emission
allowances under the acid rain control program established by Title IV of the Clean Air Act.75
Depending on the location of a new plant, it may also need to purchase NOx allowances.76
73
Renewable power plants that do not burn fuels, such as solar, wind, and geothermal power, do not have air
emissions. The depleted fuel rods from nuclear plants contain high level radioactive wastes. The nuclear fuel costs used
in this study include the federal one mill (i.e., one tenth of a cent) per kWh fee for supporting creation of a permanent
waste repository. In the interim depleted fuel is stored at each reactor site. For more information see CRS Report
RL33461, Civilian Nuclear Waste Disposal, by (name redacted).
74
BACT requirements take into account cost-effectiveness; LAER requires the lowest possible emission rate without
cost considerations. For an overview of the regulatory framework see MIT, The Future of Coal, 2007, pp. 135-136. The
federal New Source Performance Standards for new, large fossil-fired plants are found at 40 C.F.R. §60(Da).
75
An allowance is authorization to emit one unit of a pollutant during a specified time period, usually a year. For
example, under the acid rain cap and trade program, national total SO2 emissions are capped and each coal plant must
submit sufficient allowances to cover its annual emissions. Older plants can comply by staying within emission
allocations, installing control equipment, and/or buying SO2 allowances. New plants must install control equipment and
buy allowances.
76
NOx regulation is complex and involves both federal and state rules. For a summary of NOx regulation see the
(continued...)

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Regulation of mercury is unsettled. On February 8, 2008, the U.S. Court of Appeals for the D.C.
Circuit vacated the Bush administration’s Clean Air Mercury Rule, which would have allowed
new coal plants to comply with mercury emission limits by purchasing mercury allowances.
Because of the court’s action, coal plant mercury emissions are now categorized as a hazardous
air pollutant. If the decision stands,77 it will trigger a requirement for all coal plants, old and new,
to install mercury control equipment that meets a Maximum Available Control Technology
(MACT) standard. EPA has not yet defined a MACT standard for mercury, but state air officials
will probably require new plants to meet tight mercury emission limits.78
The technology and costs for controlling sulfur, NOx, particulate, and mercury emissions are
briefly described below. For additional information on emission control technologies see the
International Energy Agency Clean Coal Center at http://www.iea-coal.org/site/ieacoal/databases/
clean-coal-technologies.
•

Sulfur. Commercial technologies can remove 95% to 99% of the SO2 formed by
burning coal in pulverized coal plants, and over 99% of the sulfur in IGCC
synthesis gas before it is burned. To the degree that a new pulverized coal unit or
IGCC plant releases SO2 to the atmosphere, it must buy SO2 emission
allowances. Because SO2 emissions by plants with controls are so small,
allowances are not a major expense compared to the other costs of running a
power plant. At mid-2008 allowance and fuel prices, the annual cost of SO2
allowances for a coal plant burning eastern coal would be on the order of $1
million, compared to over $220 million just for fuel. 79 The cost of the control
equipment is more significant. An SO2 control system will account for about 12%
of the capital cost of a new pulverized coal plant and 29% of non-fuel operating
costs (Table 2). (It is difficult to isolate environmental control costs for an IGCC
plant because emissions control is largely integral with cleanup of the synthesis
gas that is necessary, irrespective of environmental rules, prior to combustion.)

•

Mercury. Some pulverized coal plants can achieve 90% removal of mercury as a
co-benefit of operating SO2 and particulate control equipment. Other plants will
have to install a powdered activated carbon injection system (accounting for
about 1% of the plant’s capital cost and 9% of non-fuel operating costs). IGCC

(...continued)
National Energy Technology Laboratory website at http://www.netl.doe.gov/technologies/coalpower/ewr/nox/
regs.html.
77
The decision has been appealed by the EPA to the U.S. Supreme Court.
78
CRS Report RS22817, The D.C. Circuit Rejects EPA’s Mercury Rules: New Jersey v. EPA, by (name redacted) and
(name redacted); Amena Saiyid, “Utilities with Permits to Build New Units Caught in MACT Regulatory Bind,”
Platts Coal Outlook, June 23, 2008.
79
A 600 MW coal plant with an 85% capacity factor and a heat rate of 9,000 btus per kWh, will consume about 40.2
trillion btus of fuel per year. At a controlled emission rate of 0.157 lbs of SO2 per million btus of fuel consumed, this
results in emissions of about 3,200 tons of SO2 annually. At a late June 2008, SO2 allowance price of $330 per ton, this
equals an annual cost of $1.1 million. Emissions and the resulting allowance cost would be still less for an IGCC. In
contrast, the fuel cost for this hypothetical plant (assuming a delivered cost of Central Appalachian coal of $137.92 per
ton and a heat content of 12,500 btus per pound) would be about $222 million per year. The SO2 system does consume
a material amount of the electricity produced by a pulverized coal plant, in the range of 1% to 3% of output. Sources:
MIT, The Future of Coal, 2007, p. 138; Spark Spreads table, Platts Coal Trader, June 30, 2008; U.S. DOE, 20% Wind
Energy by 2030, Table B-12; Delivered Coal Price Comparison table, Argus Coal Transportation, June 24, 2008.

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plants would remove 90% to 95% of the mercury from the synthesis gas using
another technology also based on activated carbon.
•

NOx. Commercial technologies can reduce NOx emissions to very low levels for
pulverized coal and IGCC plants. Depending on a plant’s location, it may have to
purchase NOx emission allowances. As in the case of SO2 allowances, because
the controlled emission rates for new plants are so low the total cost of
allowances is small compared to other plant operating costs. The cost of the
control equipment for a pulverized coal plant is about 2% of capital expense and
9% of non-fuel operating costs.

•

Particulates. Primary particulates are controlled using removal systems that have
been a standard feature of pulverized coal plants for many years. Removal
efficiencies exceed 99%. Primary particulate removal rates for IGCC plants are
expected to be similar. Secondary particulates are controlled by reducing NOx
and SO2 emissions, as discussed above.

Table 2. Emission Controls as an Estimated Percentage of Total Costs for a New
Pulverized Coal Plant
Percent of Total Cost
Plant Capital Cost

Plant O&M Cost

SO2 Controls

12%

29%

NOx Controls

2%

12%

Mercury Controls

1%

9%

Total for Emission Controls

16%

51%

Source: Calculated by CRS from MIT, The Future of Coal, 2007, Tables A-3.D.3. and Tables A-3.D.4. Calculations
were made for the point estimates in the report; the tables have cost ranges for capital costs and for mercury
control O&M costs.
Notes: SO2 = sulfur dioxide; NOx = nitrogen oxides; O&M = operations and maintenance.

Carbon Dioxide
This section of the report discusses the technical and cost characteristics of carbon control
technologies for coal and natural gas plants. The estimates of the cost and performance affects of
installing carbon controls are uncertain because no power plants have been built with full-scale
carbon capture. For additional information on carbon control technologies, see CRS Report
RL34621, Capturing CO2 from Coal-Fired Power Plants: Challenges for a Comprehensive
Strategy, by (name redacted), (name redacted), and (name redacted); and Steve Blankinship, “The
Evolution of Carbon Capture Technology, Parts 1 and 2,” Power Engineering, March and May
2008.80

80

There are also many CRS reports on climate change issues. These reports can be retrieved by using the “Energy,
Environment, and Resources” link on the CRS home page to access the “Climate Change” link.

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CO2 Removal for Pulverized Coal and Natural Gas Plants
Technology developed by the petrochemical industry, using a class of chemicals called amines,
can be used to scrub CO2 from flue gas. Amine scrubbing is currently used to extract CO2 from
part of the flue gas at a handful of coal-fired plants, to produce CO2 for enhanced oil recovery and
the food industry, but the scale is about a tenth of what would be needed to scrub 90% of the CO2
from the entire flue gas stream of a large power plant.81 Scaling up amine technology to handle
much larger gas flows at a power plant may be technically challenging.
Amine scrubbing is energy intensive. It diverts steam from power production and uses part of the
plant’s electricity production to compress the CO2 for pipeline transportation to its final
disposition. Amine scrubbing is estimated to cut a coal plant’s electricity output by about 30% to
40%.82 The equipment is also costly. According to one study, the cost for building a new coal
plant with amine scrubbing is an estimated 61% higher than building the a plant without carbon
controls.83 The same study estimated the cost for a coal plant retrofit installation, without taking
into account the recent rapid increase in power plant construction costs, at about $1,600 per kW
of net capacity, or almost $1 billion for a 600 MW plant.84
The cost and performance impacts for adding amine scrubbing to a natural gas-fired combined
cycle are also large. The estimated reduction in net electricity output is 14%, and the estimated
increase in the plant capital cost is about 100%.85 Researchers are attempting to commercialize
less costly carbon capture technologies for conventional coal and gas plants, but these are still in
early development.

81

Currently four commercial facilities in the United States treat fossil plant flue gas to recover CO2. The largest amount
of CO2 captured is about 800 tons per day. In contrast, a 600 MW coal plant would produce about 13,300 tons of CO2
daily; 90% removal would require extracting 12,000 tons of CO2 each day. (Information on current commercial
projects from HDR|Cummins & Barnard, Inc., Carbon Dioxide Capture and Sequestration, report to Alliant Energy,
April 2008, Report No. 5561.06 R-002, p. 8; and http://www.mgs.md.gov/geo/pub/co2seqpaper.pdf. CO2 emissions for
a 600 MW plant computed as follows: 600 MW x 9 million btus of fuel input per MWh x 24 hours x 205.3 pounds of
CO2 released per mmbtu of heat input for bituminous coal, divided by 2 million. Rate of CO2 released from burning
coal is from EIA, Electric Power Annual 2006, p. 92.)
82
MIT, The Future of Coal, 2007, pp. 25 and 28; “Pilot Project Uses Innovative Process to Capture CO2 From Flue
Gas,’ EPRI Journal, Spring 2008, p. 4).
83
Calculated from MIT, The Future of Coal, 2007, Table 3.1 (estimates for supercritical pulverized coal).
84
Ibid., p. 28. The cost and practicality of a retrofit would vary with specific plant conditions. Another consideration is
that retrofitting carbon capture to an IGCC plant may not be straightforward. An MIT study suggests that for technical
reasons a developer looking toward possible future carbon legislation cannot build an IGCC plant that will provide
optimal efficiency today (without carbon technology) and tomorrow (after carbon control retrofit). The developer must
make a choice that may result in suboptimal performance (higher costs and less efficiency) either in current or future
operation (MIT, The Future of Coal, 2007, pp. 149-150).
85
National Energy Technology Laboratory, Cost and Performance Baseline for Fossil Energy Plants, Volume 1, May
2007, Exhibit 5-25 and page 481; EIA, Assumptions to the Annual Energy Outlook 2008, Table 38. The plant capacity
derate for the natural gas combined cycle plant is less than for the pulverized coal plant primarily because natural gas
generation is much less carbon intensive than burning coal, so less CO2 must be processed. The lower carbon intensity
is due to the greater efficiency of a gas-fired combined cycle compared to a pulverized coal plant (fewer btus of fuel are
needed to generate a unit of electricity), and because burning a btu of gas produces about half as much CO2 as burning
a btu of coal.

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CO2 Removal for IGCC Coal Plants
Carbon capture for an IGCC plant involves multi-step treatment of the synthesis gas using
technology originally developed for the petrochemical industry. Estimates of the cost and
performance impact of incorporating carbon capture into a IGCC design vary widely. For the
sample of studies shown in Table 3, the estimated increase in capital costs ranges from 32% to
51%. The estimated loss in generating capacity varies by more than a factor of two, from 13% to
28%. This wide variation reflects in part factors specific to different IGCC technologies, but is
also an indication of limited experience with IGCC technology generally and the integration of
carbon capture in particular.
Table 3. Estimates of the Change in IGCC Plant Capacity and Capital Cost from
Adding Carbon Capture
Source and
IGCC Technology

Change in Net
Generating Capacity

Change in Plant Cost

GE/Radiant

-13%

32%

CoP E-Gas

-17%

40%

Shell

-19%

35%

n/a

43%

-25%

51%

GE/Full Quench (retrofit)

-17%

n/a

CoP E-Gas (retrofit)

-28%

n/a

Generic

-28%

32%

NETL, 2007

EIA, 2008
Generic
EPRI 2006
Shell
MIT 2007

Sources: NETL, Cost and Performance Baseline for Fossil Energy Plants, Volume 1, Exhibit 3-114; EIA, Assumptions to
the Annual Energy Outlook 2008, Table 38; EPRI, Feasibility Study for an Integrated Gasification Combined Cycle Facility
at a Texas Site, October 2006, Tables 7-1, 13-2, and 13-3; MIT, The Future of Coal, 2007, pp. 122, 150, and 151,
and Table 30.
Notes: IGCC = Integrated Gasification Combined Cycle; NETL = National Energy Technology Laboratory; EIA
= Energy Information Administration; EPRI = Electric Power Research Institute; MIT = Massachusetts Institute of
Technology; n/a = not available; GE = General Electric; CoP = ConocoPhillips. Radiant and full quench refer to
alternative means of heat capture from cooling of the synthesis gas. Values are for units built to incorporate
carbon capture, except when retrofit is indicated.

While IGCC technology is arguably better-suited for carbon capture than pulverized coal systems,
it does not currently provide a simple or inexpensive path to carbon control. In addition to the
cost and performance penalties and uncertainties, other factors complicate implementing IGCC
carbon control. For example, the nation’s largest and least expensive coal supply is western

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subbituminous coal. However, the IGCC technologies best suited for using this coal also appear
to incur the largest cost and performance penalties from adding carbon control technology.86

CO2 Allowance Costs
Congress has considered legislation that would put a cost on carbon emissions, such as the
Lieberman-Warner Climate Security Act of 2007 (S. 2191). If Congress ultimately legislates
allowance-based carbon controls, the estimated costs of such allowances are very uncertain. As an
illustration of this uncertainty, Figure 5 shows EIA’s alternative projections of CO2 allowance
prices under S. 2191. Depending on assumptions for such factors as the speed with which new
technologies are deployed and their costs, and the availability for purchase of international CO2
emission offsets, EIA’s estimate of the price of allowances by 2030 ranges from about $60 to
$160 per metric ton of CO2 (2006 dollars).

86
The dry feed Shell and ConocoPhillips E-Gas systems appear to be better suited to high moisture subbituminous and
lignite coals than the GE technology, which brings coal into the gasifier as a coal/water slurry (excess water reduces the
efficiency of the gasifier and requires more oxygen). However, the GE technology operates at higher pressures and can
use full quench cooling of the synthesis gas to produce steam for the CO2 shift reactor, which may make it the better
choice for carbon capture. MIT, The Future of Coal, 2007, pp. 149-151; EPRI, Feasibility Study for an Integrated
Gasification Combined Cycle Facility at a Texas Site, October 2006, pp. v and vi; and Nexant, Inc., Environmental
Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and Pulverized Coal Technologies, report
for the U.S. EPA, July 2006, p. 5-13.

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Figure 5. EIA’s Projections of S. 2191 CO2 Allowance Prices (2006$ per Metric Ton of
CO2 Equivalent)

Sources: Supporting spreadsheets for EIA, Energy Market and Economic Impacts of S.2191, the Lieberman-Warner
Climate Security Act of 2007, April 2008.

Even the low end of EIA’s allowance price forecasts would impose costs far beyond those of
existing air emissions regulations. Figure 6 compares the price of coal in EIA’s long-term
Reference Case projection (which assumes only current law, and therefore no carbon controls) to
EIA’s “core” case estimate of allowance prices from the S. 2191 study. Based on EIA’s forecasts,
by 2030 the allowance price is the equivalent of triple the coal price. 87 (As noted above, the
outlook for CO2 allowance prices is uncertain. Different legislative approaches and changes to
other forecasting assumptions can produce very different estimates from those shown here.)

87

For a broader summary of S. 2191 allowance price forecasts see CRS Report RL34489, Climate Change: Costs and
Benefits of S. 2191/S. 3036, by (name redacted) and (name redacted). For an example of how a different legislative
approach can effect allowance prices, see CRS Report RL34520, Climate Change: Comparison and Analysis of S. 1766
and S. 2191 (S. 3036), by (name redacted) and (name redacted).

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Figure 6. Comparison of EIA’s Reference Case Coal Prices and S. 2191 Core Case
CO2 Allowance Prices

Sources: Supporting spreadsheets for EIA, Energy Market and Economic Impacts of S. 2191, the Lieberman-Warner
Climate Security Act of 2007, April 2008; CRS calculations (assumes 20 MMBtus per ton of coal and 209 lbs. of
CO2 per MMBtu if coal consumed).

Financial Analysis Methodology and Key
Assumptions
This financial analysis of new power plants provides estimates of the operating costs and required
capital recovery of each generating technology through 2050. Plant operating costs will vary from
year to year depending, for example, on changes in fuel prices and the start or end of government
incentive programs. To simplify the comparison of alternatives, these varying yearly expenses are
converted to a uniform annualized cost expressed as 2008 present value dollars.
Converting a series of cash flows to a financially equivalent uniform annual payment is a twostep process. First, the cash flows for the project are converted to a 2008 “present value.” The
present value is the total cost for the analysis period, adjusted (“discounted” using a “discount
factor”) to account for the time value of money and the risk that projected costs will not occur as
expected. This lump-sum 2008 present value is then converted to an equivalent annual payment
using a uniform payments factor. 88

88

For a more detailed discussion of the annualization method see, for example, Chan Park, Fundamentals of
Engineering Economics, 2004, Chapter 6; or Eugene Grant, et al., Principles of Engineering Economy, 6th Ed., 1976,
(continued...)

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The capital costs for the generating technologies are also converted to annualized payments. An
investor-owned utility or independent power producer must recover the cost of its investment and
a return on the investment, accounting for income taxes, depreciation rates, and the cost of
money. These variables are encapsulated within an annualized capital cost for a project computed
using a “capital charge rate.” The financial model used for this study computes a project-specific
capital charge rate that reflects the assumed cost of money, depreciation schedule, book project
life, financing structure (percent debt and percent equity), and composite federal and state income
tax rate. For a POU project, which is 100% debt financed, a “capital recovery factor” reflecting
each project’s cost of money is computed and used to calculate a mortgage-type annual
payment.89
Combining the annualized capital cost with the annualized operating costs yields the total
estimated annualized cost of a project. This annualized cost is divided by the projected yearly
output of electricity to produce a cost per Mwh for each technology. By annualizing the costs in
this manner, it is possible to compare alternatives with different year-to-year cost patterns on an
apples-to-apples basis.
Inputs to the financial model include financing costs, forecasted fuel prices, non-fuel operations
and maintenance expense, the efficiency with which fossil-fueled plants convert fuel to
electricity, and typical utilization rates (see Appendix D, Table D-1 through Table D-4, below).
Most of these inputs are taken from published sources, such as the assumptions EIA used to
produce its 2007 and 2008 long-term energy forecasts. The power plant capital costs are
estimated by CRS based on a review of public information on recent projects. Appendixes B and
C of the report displays the data used for the capital costs estimates.

Analysis of Power Project Costs
This section of the report analyzes the cost of power from the generating technologies discussed
above. Results are first presented for a Base Case analysis. Results are then presented for four
additional cases, each of which explores a key variable that influences power plant costs. These
cases are:
•

Influence of federal and state incentives.

•

Higher natural gas price.

•

Uncertainty in capital costs.

•

Carbon controls and costs.

In each case the cost of power from a natural gas-fired combined cycle plant is used as a
benchmark for evaluating the cost of power from the other generating technologies. The gas-fired
combined cycle plant is used as a benchmark because of the dominant role it has played, and may
(...continued)
Chapter 7.
89
For additional information on capital charge rates see Hoff Stauffer, “Beware Capital Charge Rates,” The Electricity
Journal, April 2006. For additional information on the calculation of capital recovery factors see Chan Park,
Fundamentals of Engineering Economics, 2004, Chapter 2; or Eugene Grant, et al., Principles of Engineering
Economy, 6th Ed., 1976, Chapter 4.

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continue to play, as the source of new generating capacity capable of meeting baseload and
intermediate demand. The closer a generating technology comes to meeting or beating the power
cost of the combined cycle, the better its chances of competing in the market for new power
plants.
The Base Case is a starting point for comparing how different assumptions, such as for fuel and
construction costs, change estimated power costs. None of the cases is a “most likely” estimate of
future costs. Future power costs are subject to so many variables with high degrees of uncertainty
that projecting a most likely case is impractical. The object of the analysis is provide insight into
how key factors influence the costs of power plants, including factors under congressional control
such as incentive programs.
These estimates are approximations subject to a high degree of uncertainty. The rankings of the
technologies by cost are therefore also an approximation and should not be viewed as definitive
estimates of the relative cost-competitiveness of each option. Also note that project-specific
factors would weigh into an actual developer’s decisions, including how close a fossil plant
would be to fuel sources, local climate (for

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/crs%3ARL34746. Public record. Not legal advice.