Wind Power in the United States: Technology, Economic, and Policy Issues

Wind Power in the United States:
Technology, Economic, and Policy Issues
Updated October 21, 2008
Jeffrey Logan and Stan Mark Kaplan
Specialists in Energy Policy
Resources, Science, and Industry Division

Wind Power in the United States:
Technology, Economic, and Policy Issues
Rising energy prices and concern over greenhouse gas emissions have focused
congressional attention on energy alternatives, including wind power. Although wind
power currently provides only about 1% of U.S. electricity needs, it is growing more
rapidly than any other energy source. In 2007, over 5,000 megawatts of new wind
generating capacity were installed in the United States, second only to new natural
gas-fired generating capacity. Wind power has become “mainstream” in many
regions of the country, and is no longer considered an “alternative” energy source.
Wind energy has become increasingly competitive with other power generation
options, although the impacts of the current financial crisis are uncertain. Wind
technology has improved significantly over the past two decades. CRS analysis
presented here shows that wind energy still depends on federal tax incentives to
compete, but that key uncertainties like climate policy, fossil fuel prices, and
technology progress could dominate future cost competitiveness.
A key challenge for wind energy is that electricity production depends on when
winds blow rather than when consumers need power. Wind’s variability can create
added expenses and complexity in balancing supply and demand on the grid. Recent
studies imply that these integration costs do not become significant (5-10% of
wholesale prices) until wind turbines account for 15-30% of the capacity in a given
control area. Another concern is that new transmission infrastructure will be required
to send the wind-generated power to demand centers. Building new lines can be
expensive and time-consuming, and there are debates over how construction costs
should be allocated among end-users and which pricing methodologies are best.
Opposition to wind power arises for environmental, aesthetic, or aviation
security reasons. New public-private partnerships have been established to address
more comprehensively problems with avian (bird and bat) deaths resulting from wind
farms. Some stakeholders oppose the construction of wind plants for visual reasons,
especially in pristine or highly-valued areas. A debate over the potential for wind
turbines to interfere with aviation radar emerged in 2006, but most experts believe
any possible problems are economically and technically manageable.
Federal wind power policy has centered primarily on the production tax credit
(PTC), a business incentive to operate wind facilities. The PTC is currently set to
expire on December 31, 2009. Analysts and wind industry representatives argue that
the on-again off-again nature of the PTC is inefficient and leads to higher costs for
the industry. A federal renewable portfolio standard — which would mandate wind
power levels — was rejected in the Senate in late 2007; its future is uncertain.
If wind is to supply up to 20% of the nation’s power by 2030, as suggested by
a recent U.S. Department of Energy report, additional federal policies will likely be
required to overcome barriers, and ensure development of an efficient wind market.

In troduction ......................................................1
Background ......................................................2
The Rise of Wind..............................................3
Benefits and Drawbacks of Wind Power............................5
Wind Resources and Technology......................................8
Wind Power Fundamentals......................................8
Physical Relationships......................................8
Wind Resources...............................................9
Offshore Wind...........................................11
Wind Power Technology.......................................11
Types of Wind Turbines...................................12
Capacity Factor..........................................14
Wind Research and Development Emphasis....................14
Wind Industry Composition and Trends...............................15
Wind Turbine Manufacturers and Wind Plant Developers.............18
International Comparisons......................................19
Wind Power Economics............................................22
Cost and Operating Characteristics of Wind Power..................23
Wind Operation and System Integration Issues..................24
Levelized Cost Comparison.....................................26
Wind Policy Issues................................................32
Siting and Permitting Issues.....................................32
Transmission Constraints.......................................36
Federal Renewable Transmission Initiatives....................38
Renewable Production Tax Credit................................39
PTC Eligibility: IOUs vs. IPPs..............................40
Specific PTC Legislative Options............................40
Carbon Constraints and the PTC.............................41
Alternatives to the PTC....................................41
Renewable Portfolio Standards..................................42
Federal RPS Debate.......................................42
Conclusions .....................................................43
Appendix. Financial Analysis Methodology and Assumptions.............44
List of Figures
Figure 1. Cumulative Installed U.S. Wind Capacity.......................3
Figure 2. Wind Power Aerodynamics..................................8
Figure 3. U.S. Wind Resources Potential..............................10

Figure 5. Components in a Simplified Wind Turbine.....................13
Figure 6. Installed Wind Capacity By State in 2007......................16
Figure 7. Existing and Planned North American Wind Plants by Size........17
Figure 8. U.S. Wind Turbine Market Share by Manufacturer in 2007........18
Figure 9. Global Installed Wind Capacity By Country....................20
Figure 10. Component Costs for Typical Wind Plants....................23
List of Tables
Table 1. Wind Energy Penetration Rates by Country.....................20
Table 2. Assumptions for Generating Technologies......................27
Table 3. Economic Comparison of Wind Power with Alternatives...........31
Table 4. Selected Wind Power Tax Incentive Bills Compared..............41
Table A-1. Base Case Financial Factors...............................47
Table A-2. Base Case Fuel and Allowance Price Forecasts................48
Table A-3. Power Plant Technology Assumptions.......................49

Wind Power in the United States:
Technology, Economic and Policy Issues
Rising energy prices and concern over greenhouse gas emissions have focused
congressional attention on energy alternatives, including wind power. Although wind
power currently provides only a small fraction of U.S. energy needs, it is growing
more rapidly than any other electricity source. Wind energy already plays a
significant role in several European nations, and countries like China and India are
rapidly expanding their capacity both to manufacture wind turbines and to integrate
wind power into their electricity grids.
This report describes utility-scale wind power issues in the United States. The
report is divided into the following sections:
!Background on wind energy;
!Wind resources and technology;
!Industry composition and trends;
!Wind power economics; and
!Policy issues.
Three policy issues may be of particular concern to Congress:
!Should the renewable energy production tax credit be extended past
its currently scheduled expiration at the end of 2009, and, if so, how
would it be funded? The economic analysis suggests that the credit
significantly improves the economics of wind power compared to
fossil and nuclear generation.
!Should the Congress pass legislation intended to facilitate the
construction of new transmission capacity to serve wind farms? As
discussed below, sites for wind facilities are often remote from load
centers and may require new, expensive transmission infrastructure.
Texas and California have implemented state policies to encourage
the development of new transmission lines to serve wind and other
remote renewable energy sources. Legislation before the Congress
would create a federal equivalent.
!Should the Congress establish a national renewable portfolio
standard (RPS)? As discussed in the report, the economics of wind
are competitive, but not always compelling, compared to fossil and
nuclear energy options, and because wind power is dependent on the

vagaries of the weather it is not as reliable as conventional sources.
Some benefits of wind power cited by proponents, such as a long-
term reduction in demand for fossil fuels, are not easily quantified.
To jump-start wind power development past these hurdles, many
states have instituted RPS programs that require power companies
to meet minimum renewable generation goals. A national RPS
requirement has been considered and, to date, rejected by Congress.
Other policy questions, such as federal funding for wind research and
development, and siting and permitting requirements, are also outlined.
The modern wind industry began in the early 1980s when the first utility-scale1
turbines were installed in California and Denmark. Wind power then, as today, was
driven by high energy prices, energy insecurity, and concern about environmental
degradation. Early wind turbines, installed primarily at Altamont Pass outside of San
Francisco in California, were primitive compared to today’s machines, and suffered
from poor reliability and high costs. Like most new technology, early wind turbines
had to go through a process of “learning by doing,” where shortcomings were
discovered, components were redesigned, and new machines were installed in a
continuing cycle.
Today’s wind industry is notably different from that in the early 1980s. Wind
turbines now are typically 100 times more powerful than early versions and employ
sophisticated materials, electronics, and aerodynamics. Costs have declined, making
wind more competitive with other power generation options. Large companies and
investment banks now drive most wind power activity compared to the early days of2
collaborating scientists, inventors, and entrepreneurs.
From the mid-1980s to the late 1990s the U.S. wind industry stagnated due to
low energy prices and the technology’s reputation for high cost and low reliability.
But researchers continued to make improvements in the technology, driving down
costs and improving reliability. New federal and state incentives encouraged
developers to focus on the production of electricity at wind plants (also known as
wind farms) and not just installing the equipment.3 In 1999, the U.S. industry began
a period of rapid expansion, slowed occasionally by expiring federal incentives.

1 T. Gray, Proceedings of the Wind Energy and Birds/Bats Workshop: Understanding and
Resolving Bird and Bat Impacts, American Wind Energy Association and American Bird
Conservancy, September 2004, p. 6.
2 R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation, Cost and
Performance Trends: 2007, U.S. Department of Energy (DOE), May 2008, p.14.
3 Investment tax credits in the 1980s offered incentives for the installation of wind
equipment. They did not reward wind project developers for actually generating electricity.
From the 1990s through today, production tax credits have encouraged builders to maximize
the output of wind electricity since they earn credits for each kilowatt-hour generated.

Strong growth continues to this day, but whether that growth will continue in the face
of the current financial crisis is unclear.
The Rise of Wind
Wind power is no longer an “alternative” source of energy in many regions of
the country.4 It is the fastest growing source of new power generation in the United
States. Between 2004 and 2007, installed wind turbine generating capacity increased
by 150% (see Figure 1), and power generation from wind turbines more than5
Figure 1. Cumulative Installed U.S. Wind Capacity



10,000tts (M
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Source: U.S. Department of Energy, Wind Powering America Program, 2008.
4 This statement is supported by the economic analysis presented later in the report; by the
fact that wind accounts for over 6% of total in-state electricity generation in Minnesota,
Iowa, Colorado and South Dakota; and by the amount of proposed wind power projects
under development (225,000 megawatts) in 2007 compared to all other power plants
(212,000 megawatts) combined. See R. Wiser and M. Bolinger, Annual Report on U.S. Wind
Power Installation, Cost, and Performance Trends: 2007, DOE, May 2008, pp. 7-10.
5 Electric generating capacity, measured in watts, is an expression of instantaneous power
output. Electricity generation is measured in watt-hours and is an expression of energy
produced over time. For example, a 1,000 watt generator that operates all day would
produce 24,000 watt-hours (24 kilowatt-hours) of energy. Prefixes kilo (thousand), mega
(million), giga (billion), and tera (trillion) are often used with these units. Capacity
references are from: Energy Efficiency and Renewable Energy, “Wind Powering America
Program,” DOE, January 2008. [
windpoweringamerica/wind_installed_capacity.asp]. Generation references are from:
Energy Information Administration (EIA), Supplement to the Electric Power Monthly March
2008, Table ES.1.B, DOE, April 2008; and EIA, Electric Power Monthly March 2005, Table
ES.1.B., DOE, April 2005.

Only the amount of new natural gas-fired generating capacity installed during
this period exceeded that of wind.6 In 2007 the U.S. wind power industry brought
over 5,000 megawatts of new generating capacity on-line, the largest annual increase
ever by any country.7 The United States was not alone in strong growth for wind
power in 2007: global installations rose by 27% to reach a total of 94,123
megawatts.8 Only Germany, with 22,247 megawatts, has more wind power capacity
than the United States.9
Wind power’s growth is driven by a combination of the following:
!improvements in wind energy technology,
!high and volatile fossil fuel prices,
!the federal wind production tax credit (PTC) incentive,10
!state renewable portfolio standards (RPS),11
!difficulty siting and financing new coal-fired power plants given
expectation of a future carbon constraint, and
!consumer preference for renewable energy.
However, wind power still accounts for only about 1% of the total electricity
generated in the United States.12 In some regions, a lack of transmission capacity is
already beginning to constrain further growth in the wind power sector. And in states
like Iowa, Texas, and Minnesota, where wind power has achieved a higher share of
total electricity generation, there are concerns that additional wind power could lead
to higher prices or threaten grid security. Finally, there is currently a shortage of
wind turbine components and a backlog in scheduling transmission interconnection,
leading to delays and rising costs.

6 New wind plants accounted for roughly 30% of total new power plant capacity installed
in the United States in 2007. “Installed U.S. Wind Power Capacity Surged 45% in 2007,”
American Wind Energy Association, January 17, 2008.
7 Global Wind 2007 Report, Global Wind Energy Council, 2008, p.64.
8 Global Wind 2007 Report, Global Wind Energy Council, 2008, p. 6.
9 Global Wind 2007 Report, Global Wind Energy Council, 2008, pp.8-10.
10 The PTC is an incentive for business developers of wind farms and other renewable
energy projects that produce electricity. It is discussed in the Policy Issues section later in
this report. Also see CRS Report RL34162, Renewable Energy: Background and Issues for
the 110th Congress, by Fred Sissine.
11 Twenty-six states and the District of Columbia currently have mandatory RPS programs,
requiring utilities to provide a minimum percentage of their electricity from approved
renewable energy sources. Five others have non-binding goals. These numbers are reported
by the Federal Energy Regulatory Commission (FERC) and can be accessed at
[ ht t p: / / www.f e r c .gov/ mar ke t -over si ght / mkt -e l e ct r i c/ over vi ew/ e l ec-ovr -r ps.pdf ] .
12 Wind farms in the United States generated approximately 32 billion kilowatt-hours in
2007 compared to total power sector generation of 4,160 billion kilowatt-hours. Energy
Information Administration (EIA), Electric Power Monthly, DOE, March 2008 Edition,
Table ES1.B. The American Wind Energy Association forecasts that the U.S. wind industry
will generate 48 billion kilowatt-hours of electricity in 2008.

Benefits and Drawbacks of Wind Power
There are frequently noted benefits and drawbacks to wind energy. Text Box
1 and Text Box 2 summarize selected problems and benefits, respectively, for wind
Drawbacks. A key challenge for windText Box 1. Selected
energy is that electricity production depends onProblems Facing Wind
when and how consistently winds blow rather thanPower
when consumers most need power. This variability
can create added expenses and complexity in- Power output depends on
balancing supply and demand on the grid.13 Severalwhen the wind blows, not
recent studies note that system integration costs dowhen users need electricity.
not become significant ($3 to $5 per megawatt-- New transmission
hour) until wind turbines account for 15-30% of theinfrastructure is often
capacity in a control area.14 These apparentlyrequired.
modest cost estimates have yet to be confirmed- Depends on inconsistentfederal incentives.
within the context of the U.S. electricity system.- Causes bird and bat
Another concern is that new transmissiondeaths.- Considered unsightly by
infrastructure may be required to send the wind-some.
generated power to where it is needed. This can be- Can interfere with radar in
an expensive and time-consuming effort. There aresome cases.

debates over how construction costs should be
allocated among end users and which pricing
methodologies are most economically efficient. Although transmission constraints
face all new power generating options, wind power is especially handicapped because
wind resources are often far from demand centers and do not usually use the full
capacity of the transmission line due to the variable output. Texas is analyzing new
transmission capacity to send wind-generator power from West Texas to the more
populated northern and eastern sections of the state that could cost from $3 billion
to over $6 billion.15 On a national scale, the U.S. Department of Energy (DOE) states
that the most cost-effective way to meet a 20% wind energy target by 2030 would be
by constructing over 12,000 miles of new transmission lines at a cost of
approximately $20 billion.16 (See the section on Transmission Constraints for more
on this issue.)
13 These issues are further discussed in the Wind Operation and Systems Integration Issues
section of this report.
14 This is about 5-10% of the price of typical wholesale electric power, according to CRS
calculations. R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation,
Cost and Performance Trends: 2006, U.S. DOE, May 2007, p. 20.
15 “ERCOT Files Wind Transmission Options with Commission,” Electric Reliability
Council of Texas (ERCOT) Press Release, April 2, 2008.
16 Energy Efficiency and Renewable Energy, 20% Wind Energy by 2030: Increasing Wind
Energy’s Contribution to U.S. Electricity Supply, U.S. DOE, May 2008, p. 95.

Wind power is supported by federal and state incentives. In 2007, the Energy
Information Administration (EIA) of DOE estimated that federal incentives for wind
— primarily the PTC — totaled $724 million.17 In 2008, incentives could exceed
$1 billion if wind generation expands from 32 billion kilowatt-hours to 48 billion
kilowatt-hours as estimated by the American Wind Energy Association (AWEA), a
national trade association promoting wind. Costs to states using RPS policies are
difficult to estimate because they are mandated requirements. Some believe that
these are high costs to pay for a relatively small amount of energy. Others note that
wind energy is an evolving technology and additional breakthroughs are possible.
Many in the industry believe that the on-again, off-again nature of the federal PTC
incentives harm rational development of the sector.18
Among some critics, wind power also results in unacceptable bird and bat
deaths. To others, it is the visual impacts that wind turbines have on the landscape,
or the noise that causes objection. Finally, increasingly tall wind turbines have
interfered with military and airport radar. These issues are discussed in a later section
of the report.
Benefits. Wind turbines have no direct emissions of air pollutants, including
oxides of sulfur and nitrogen, mercury, particulates, and carbon dioxide.19 They also
offset the need to mine, process, and ship coal and uranium; drill and transport
natural gas (and to a much lesser degree, oil); and construct or maintain hydroelectric
dams. As noted previously, wind power contributed approximately 32 billion
kilowatt-hours of electricity to the U.S. electricity grid in 2007; if that electricity had
been generated using the average mix of power plants in the United States, an
additional 19.5 million tons of carbon dioxide would have been released that year.20

17 EIA, Federal Financial Interventions and Subsidies in Energy Markets 2007, U.S. DOE,
April 2008, Table ES5.
18 M. Barradale, “Impact of Policy Uncertainty on Renewable Energy Investment: Wind
Power and PTC,” U.S. Association for Energy Economics Working Paper No. 08-003,
January 2008.
19 Wind power does have “lifecycle emissions” associated with the materials that go into
turbine and transmission line construction, operation and maintenance activities, and
decommissioning. A study by the International Energy Agency estimated lifecycle carbon
dioxide emissions for wind power at 7-9 grams of CO2 per kilowatt-hour. For comparison,
coal- and natural gas-fired plants released 955 and 430 grams per kilowatt-hour,
respectively. International Energy Agency, Benign Energy?: The Environmental
Implications of Renewables, Table 3-1 and 3-2, 1998.
20 CRS calculation based on EIA data for 2006 and estimates for 2007. EIA, Electric Power
Monthly, U.S. DOE, April 15, 2008, Table ES1.B. For comparison, total U.S. electric power
sector emissions of carbon dioxide in 2006 were over 2,500 million tonnes. EIA, Electric
Power Annual, U.S. DOE, Table 5.1, October 2007.

Given rising prices for coal, natural gas, andText Box 2. Selected
nuclear fuel, power suppliers are drawn to theBenefits of Wind Power
certainty that wind — while variable — is
inexhaustible and has no fuel cost. By displacing- Operations do not produce
coal-fired and gas-fired generation, wind powercarbon dioxide or other air
would reduce the demand for these fuels, perhapspollutants.
moderating future prices and price volatility. - Reduces power market
exposure to volatile fuel
Wind plants can catalyze rural developmentprices.
because farmers and ranchers receive royalty- Assists rural development
payments from wind developers who lease theirby giving landownersincome from land leases.
land; the vast majority remains available for crops- May provide more “green
or grazing. Farmers and ranchers typically receivejobs” than other power
from project developers $2,000-5,000 per year forgeneration options.
each turbine on their land.21 The land taken out of- Offers shorter construction
production for wind turbine pads, access roads, andlead time than some other
ancillary equipment reduces income for cornoptions.
farmers, for example, by about $165 per turbine.22- Provides competitive
electricity, especially at
Wind energy provides an additional source ofpeak times.
revenue for local governments in the form of- Does not require water for
property taxes on wind plant owners. Windoperations.

turbines — unlike fossil and nuclear power plants
— do not require water for cooling, a potentially
important issue in areas with scarce water resources. Also, the lead time for planning
and constructing wind plants is shorter than that for nuclear and coal, assuming
transmission access is not an issue.
Finally, wind power proponents argue that wind energy creates “green collar”
manufacturing and field service jobs rather than traditional carbon-intensive
employment.23 A study by Navigant Consulting in February 2008 estimated that
76,000 U.S. jobs in the wind industry were at risk if the PTC is not renewed well
21 “Wind Power’s Contribution to Electric Power Generation and Impact on Farms and Rural
Communities,” Government Accountability Office, GAO-04-756, September 2004, p. 1.
22 According to the U.S. Department of Agriculture (USDA), projected revenue in 2008-09
for corn grown in the United States is $846 per acre. (See World Agricultural Supply and
Demand Estimates, USDA, May 9, 2008, p. 12.) Total expenses per acre to produce this
corn in 2006 were $410 (See “Commodity Costs and Returns: U.S. and Regional Cost and
Return Data,” USDA Economic Research Service, available at [
Data/CostsAndReturns/data/current/C-Corn.xls]. Expenses for 2008-09 have increased due
to higher fuel and fertilizer costs. Assuming these expenses to be 25% higher in 2008-09
leads to $513 per acre, and net income of $333 per acre. According to NREL, about 0.5
acres of land is removed from production for each turbine, leading to a loss of corn
production of about $165 dollars per turbine. (See “Power Technologies Energy Data Book:
Wind Farm Area Calculator,” NREL. Available at [
23 S. Greenhouse, “Millions of Jobs of a Different Collar,” New York Times, March 26,


before its expiration in December 2008.24 It is unclear how many U.S. jobs are at risk
if traditional power plants are not built.
Wind Resources and Technology
This section begins with a description of how wind turbines work. It then
provides information on wind resources in the United States, both on and offshore.
Finally, the section outlines technology trends in the wind power sector.
Wind Power Fundamentals
Unequal solar heating of the Earth’sFigure 2. Wind Power
atmosphere and oceans creates wind.Aerodynamics

Wind turbine blades, like airplane
wings, produce lift when air passes over
one side of their shaped surface more
rapidly than another (Figure 2). This lift
spins the turbine blades and rotor, which
is connected to a generator through a
gearbox inside the housing. The
generator, and accompanying power
conditioning equipment, then delivers
electricity to the transmission grid at the
appropriate voltage and frequency. The
process is roughly opposite to a common
household fan, which uses electricity to
turn the blades and create air motion.
Wind turbines can stand alone or be
integrated into wind farms with power
generating capacity equaling that of a25
traditional power plant. This report focuses only on large, utility-scale wind
turbines. Smaller, off-grid wind power applications are also growing rapidly,26
although their aggregate impact is limited.
Physical Relationships. The evolution of wind power technology and
market development has been influenced by three physical relationships. First, a
24 “Economic Impacts of Tax Credit Expiration,” Navigant Consulting, prepared for the
American Wind Energy Association and the Solar Energy Research and Education
Foundation, February 2008, p. 21.
25 Typical new U.S. wind plants ranged from 100 to 300 megawatts of installed capacity in
2007. Horse Hollow (Texas) is the largest U.S. wind plant, at 736 megawatts. Although
some wind plants have capacity on par with traditional fossil fuel power plants, they
produce comparatively less electricity because winds blow inconsistently.
26 See Energy Efficiency and Renewable Energy, Small Wind Electric Systems: A U.S.
Consumer’s Guide, DOE, March 2005.

wind turbine’s power output varies with the cube of wind speed.27 Thus, all else held
constant, if wind velocity doubles, power output increases eight-fold. Wind power
developers, therefore, face the challenge of finding where winds blow best. Winds
at 250 feet in altitude are stronger and steadier than those closer to the ground; this
factor explains why wind turbine towers are placed high in the air.
Second, power output varies with the area swept out by the turbine blades
during their rotation. Doubling a turbine blade’s length will yield a quadrupling of
power output. Today’s utility-scale wind turbine blades are commonly 130 feet long
or more in an attempt to harness more energy. Turbine manufacturers have devoted
attention over the past two decades to finding materials strong and durable enough
to handle the twisting forces that are transmitted from the longer blades through the
rotor and gearbox in fluctuating winds.
Finally, power output increases directly with air density. Density is typically
higher in winter months and at low altitudes, and lower in summer months and at
high altitudes. Winds near the cold Scandinavian seas, for example, contain more
exploitable energy than those of the hot, high-altitude desserts of the American
Wind Resources
Wind resources in the United States, and elsewhere, have been studied for
decades. The National Renewable Energy Laboratory (NREL) has produced national
and state wind resource maps that indicate areas with promising winds (Figure 3).28
“Excellent” winds mean those that average about 17 miles per hour or above at 150
feet in altitude. Additional mapping efforts characterize seasonal and even daily
variations in average wind speed. After using these maps to identify promising
regions, wind plant developers must still study and document local conditions
carefully — often for 12 months or longer — to ensure potential financiers that
revenue streams will be sufficient and stable.

27 Cubing a number requires multiplying it by itself 2 additional times (i.e, 23 = 2x2x2 = 8).
The mathematical formula for wind turbine power output (P), usually measured in watts, is3
P = k DAV,
where k is a constant that depends on turbine design characteristics and physical limitations,2
D is the density of air, A is the area swept out by the turbine rotor blades (namely, Br, with
r being the length of the rotor blade), and V is the wind velocity.
28 For wind mapping resources, see NREL website [].

Figure 3. U.S. Wind Resources Potential

DOE estimates that total U.S. wind energy potential is over 10,000 billion
kilowatt-hours annually — more than twice the total electricity generated from all
sources in America today.29 While this potential is not realistically achievable, wind
power advocates, supported by a recent DOE study, believe that wind power could
realistically contribute 20% of the nation’s total electricity generation by the year
2030.30 The U.S. Great Plains states contain most of the best onshore wind
resources.31 The main drawback to these rich wind resources is that they are located
far from densely populated areas and thus require the construction of transmission
lines to send the electricity to the load. Building these lines is often expensive, time
consuming, and controversial.32
29 This is the theoretical potential. Energy Efficiency and Renewable Energy, Wind
Powering America: Clean Energy for the 21st Century, DOE, September 2004.
30 Office of Energy Efficiency and Renewable Energy, 20% Wind Energy by 2030:
Increasing Wind Energy’s Contribution to U.S. Electricity Supply, DOE, May 2008.
31 The U.S. Great Plains states include parts of Colorado, Kansas, Montana, Wyoming,
North Dakota, South Dakota, Nebraska, Oklahoma, New Mexico, and Texas. From a
geographical standpoint the region extends into the Canadian provinces of Alberta,
Manitoba, and Saskatchewan.
32 See CRS Report RL33875, Electric Transmission: Approaches for Energizing a Sagging
Industry, by Amy Abel.

Offshore Wind. The U.S. Department of the Interior (DOI) estimates that
over 90,000 megawatts of wind resource potential lies off the coasts of New England33
and the Mid-Atlantic states in waters less than 100 feet deep. Offshore sites
generally have higher quality winds and are located closer to population centers, but
their development costs are significantly higher. Offshore wind projects have been
slow to develop in the United States due to these high costs and public opposition.
In Europe, a total of 1,099 megawatts of offshore wind had been installed by the end
of 2007.34
The 420 megawatt Cape Wind project near Cape Cod, Massachusetts, is the
largest proposed U.S. offshore wind project to date and is currently awaiting a permit
from the DOI’s Minerals Management Service (MMS).35 During the 109th Congress,36
a debate erupted over the project’s safety, cost, and environmental impact. Cape
Wind and other proponents say the project is a safe, clean way to develop renewable
energy and create jobs. Opponents of the project have collaborated to create the
Alliance to Protect Nantucket Sound. According to the Alliance, the project poses
threats to the area’s ecosystem, maritime navigation, and the Cape Cod tourism
MMS released a Draft Environmental Impact Statement (EIS) for the Cape37
Wind project in March 2008. The draft EIS did not indicate any critical factors that
could derail the project. A final EIS is expected later in 2008. Other offshore U.S.38
wind projects have been proposed in Delaware (Bluewater) and Texas (Galveston).
Wind Power Technology
Commercial, utility-scale wind turbines have evolved significantly from their
early days in the 1980s and 1990s (Figure 4). They are larger, more efficient, and
more durable. How wind technology evolves in the future could be influenced by

33 This estimate excludes two-thirds of the offshore areas ranging from 5 to 20 nautical miles
from the shoreline to account for shipping lanes and wildlife, and view shed concerns; and
one-third of the areas from 20 to nautical 50 miles out. See Technology White Paper: Wind
Energy Potential on the U.S. Outer Continental Shelf, DOI, May 2006, pp. 1-2.
34 R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation, Cost and
Performance Trends: 2007, U.S. Department of Energy, May 2008, p. 9.
35 MMS manages the nation’s Outer Continental Shelf oil, natural gas, and other mineral
resources. The Energy Policy Act of 2005 (EPACT05) granted MMS additional authority
to act as the lead federal agency for offshore renewable energy projects. EPACT05 §388
stipulates that MMS authority does not supercede the existing authority of any other agency
for project permitting, so a wind project on the OCS may also require other permits to
operate, although leasing and environmental review would be conducted by MMS.
36 In 2006, the Senate considered a provision to the Coast Guard appropriations bill giving
the governor of Massachusetts authority to veto the Cape Wind project. A compromise was
reached that gave the Coast Guard greater authority over navigational safety related to the
project, but denied gubernatorial veto power. See §414 of P.L. 109-241.
37 See [].
38 See Offshore Wind Energy website [].

congressional policy, both in research and development funding, and through
regulatory frameworks that influence market behavior.
Figure 4. Evolution of U.S. Commercial Wind Technology

Utility-scale wind turbines have grown in size from dozens of kilowatts in the
late 1970s and early 1980s to a maximum of 6 megawatts in 2008.39 The average
size of a turbine deployed in the United States in 2007 was 1.6 megawatts, enough
to power approximately 430 U.S. homes.40 The average size of turbines continues
to expand as units rated between 2 and 3 megawatts become more common. Larger
turbines provide greater efficiency and economy of scale, but they are also more
complex to build, transport, and deploy.
Types of Wind Turbines. Industrial wind turbines fall into two general
classes depending on how they spin: horizontal axis and vertical axis, also known as
“eggbeater” turbines. Vertical axis machines, which spin about an axis perpendicular
to the ground, have advantages in efficiency and serviceability since all of the control
equipment is at ground level. The main drawback to this configuration, however, is
that the blades cannot be easily elevated high into the air where the best winds blow.
As a result, horizontal axis machines — which spin about an axis parallel to the
ground rather than perpendicular to it — have come to dominate today’s markets.41
39 The German company Enercon is testing two different 6 megawatt turbines, although they
are not yet available on commercial markets. The largest commonly used commercial wind
turbines are the 3.6 megawatt offshore units produced by Siemens and General Electric.
40 This assumes a capacity factor (see following subsection) of 34% and an EIA estimate of
the average U.S. household consumption of 11,000 kilowatt-hours per year.
41 Horizontal turbines are further divided into classes depending on generator placement,
type of generator, and blade control. For example, downwind turbines have their blades

A simplified diagram of a typical horizontal axis wind turbine is shown in
Figure 5. The blades connect to the rotor and turn a low-speed shaft that is geared
to spin a higher-speed shaft in the generator. An automated yaw motor system turns
the turbine to face the wind at an appropriate angle.42
Figure 5. Components in a Simplified Wind Turbine

There are barriers to the size of wind turbines that can be efficiently deployed,
especially at onshore locations. Wind turbine components larger than standard over-
the-road trailer dimensions and weight limits face expensive transport penalties.43
41 (...continued)
behind the generator and upwind turbines, in front. Generators can be asynchronous with
the grid, or operate at the same frequency. Blade speed can be fixed or variable, and
controlled through pitch or stall aerodynamics. For a more complete discussion of wind
turbine technical issues, see P. Carlin, A. Laxson, and E. Muljadi, The History and State of
the Art of Variable-Speed Wind Turbines, NREL, February 2001.
42 Generally, the yaw control will position the turbine to face the wind at a perpendicular
angle. The turbine can avoid damage from excessive wind speeds by yawing away from the
wind or applying the brake.
43 The standard trailer for an 18-wheel tractor trailer is approximately 12.5 feet high and 8
feet wide. Gross vehicle weight limitations are 80,000 pounds, corresponding to a cargo

Other barriers to increasingly large turbines include (1) potential for aviation and
radar interference, (2) local opposition to siting, (3) erection challenges (i.e,
expensive cranes are needed to lift the turbine hubs to a height of 300 feet or more),
and (4) material fatigue issues. Some of these issues are discussed in more detail
Capacity Factor. As noted above, a wind turbine’s power output depends on
wind speed. Capacity factor — a measure of how much electricity a power plant
actually produces compared to its potential running at full load over a given period
of time — is a useful tool to summarize average annual wind availability and speed
for wind projects. The capacity factor a wind plant achieves strongly influences the
cost of electricity produced and the profitability of the project. (See Wind Power
Economics section later in this report.)
Capacity factors for power generation technologies vary considerably. Nuclear
plants run nearly continuously at full load and only shut down under normal
conditions to be refueled. The industry-wide average capacity factor for U.S. nuclear
power plants has been about 90% in recent years. Coal plants average a capacity
factor of 70%, but individual plants can have a much higher or lower utilization rate.
Wind plants, on the other hand, have capacity factors typically ranging from 20% to44
40%. Wind turbines usually spin 65% to 90% of the time, but only at their full
rated capacity about 10% of the time. A recent study pegs the typical capacity factor45
for wind turbines at 34%. Offshore wind turbines generally have higher capacity
factors than onshore units because ocean winds are steadier than those over land.
A high capacity factor helps lower a plant’s levelized, or annualized, cost of
electricity (see section on Wind Power Economics). While a low capacity factor may
result in relatively high costs per kilowatt-hour, a complete economic analysis would
depend on when the electricity was produced. Since electricity is valued at different
prices according to daily and seasonal demand profiles, when a wind turbine actually
produces electricity can be as important as its overall capacity factor.
Wind Research and Development Emphasis. Future advances in wind
turbine technology are likely to be evolutionary rather than revolutionary.46
According to the NREL, which carries out much of DOE’s wind research and

43 (...continued)
weight of 42,000 pounds. According to NREL, the trailer limitations have the greatest
impact on the base diameter of wind turbine towers. R. Thresher and A. Laxson, “Advanced
Wind Technology: New Challenges for a New Century,” NREL, June 2006.
44 Renewable Energy Research Laboratory, “Wind Power: Capacity Factor, Intermittency,
and What Happens When the Wind Doesn’t Blow?,” University of Massachusetts at
Amherst, p. 1, November 2004.
45 Comparative Costs of California Central Station Electricity Generation Technologies,
California Energy Commission, Appendix B, December 2007, p. 67.
46 B. Parsons, “Grid-Connected Wind Energy Technology: Progress and Prospects,” NREL,

1998, p. 5.

development (R&D) program, current efforts to improve wind power technology and
reduce costs includes:
!offshore turbine deployment,
!drivetrain (gearbox) innovation,
!blade design innovation,
!mechanical and power controls,
!low wind speed turbine development,
!manufacturing economies of scale, and
!system integration improvement.47
Another general area of R&D activity is in energy storage. Energy storage does
not increase power output — in fact, energy conversion always results in lost power
— but storage can make wind power available when it is most needed. Currently,
most energy storage options are expensive and still under development.
The most common energy storage method is hydroelectric pumped storage.
During periods of strong winds and low power demand, wind turbine output can be
used to pump water into a reservoir at a higher elevation. The water can be released
through a hydroelectric generator later when the power is most needed. Many
countries have only limited pumped storage capacity and may have already exploited
what exists. In the United States, pumped storage accounts for several percent of
conventional hydroelectric power generation,48 but probably does not have potential
to grow significantly since many of the most economic sites have already been
developed and the public opposes new large-scale hydroelectric projects.
Other energy storage options such as compressed air energy storage and
advanced batteries face technical hurdles and high costs. Public and private sector
R&D is underway to bring down costs for these options, not just for the benefit of
wind power, but other variable energy sources as well.49 A technological
breakthrough in one of these storage options could enhance the ability of wind energy
to supply large quantities of electricity on demand, but whether such breakthroughs
are forthcoming is unpredictable.50
Wind Industry Composition and Trends
Within the United States, Texas is now the dominant state for wind power,
followed by California, Minnesota, Iowa, Washington, and Colorado. Total installed
wind capacity for each state at the end of 2007 is shown in Figure 6. California’s
early lead in wind power has been eclipsed by rapid growth in Texas. Wind power

47 S. Butterfield, “Technology Overview: Fundamentals of Wind Energy,” NREL, 2005.
48 EIA, Annual Energy Review 2006, U.S. DOE, 2007, Table 8.2a.
49 For more information, see U.S. Climate Change Technology Program: Technical Options
for the Near and Long Term, August 2005. []
50 For more information on U.S. R&D on wind power, see 20% Wind Energy by 2030:
Increasing Wind Energy’s Contribution to U.S. Electricity Supply, DOE, May 2008.

installations are also growing rapidly in the Pacific Northwest states of Washington
and Oregon, as well as in Colorado, Minnesota, Iowa, Illinois, and the Dakotas.
Most of these states have good wind resources, renewable portfolio standards, and
local government proponents to help overcome construction barriers. These state and
local incentives supplement the federal production tax credit incentive. The
Southeastern region of the United States is noticeably empty of wind power projects
due primarily to poor wind resources. This issue may also influence the region’s
general opposition to a national RPS.
Figure 6. Installed Wind Capacity By State in 2007
A more detailed map showing the location of each existing and planned wind
plant in North America by size is presented in Figure 7. Although planned wind
projects far surpass the number of existing ones, there is no guarantee that they will
all be constructed. Comparing wind resources from Figure 3 with existing and
planned wind plants in Figure 7 shows significant potential to continue tapping some
of the best wind sites in the upper Great Plains region. Limited transmission capacity
is one of the reasons high-quality wind regions like this are not seeing greater wind
plant development.

Figure 7. Existing and Planned North American Wind Plants by Size

Source: Ventyx Energy, the Velocity Suite. Data reportedly updated through June 5, 2008. Note: Data for wind plants in Hawaii and Alaska are not available for this map.

Wind Turbine Manufacturers and Wind Plant Developers
The major wind turbine suppliers to wind plants in the United States include
General Electric (GE) Wind, Siemens, Vestas, Mitsubishi, Suzlon, and Gamesa.
The 2007 U.S. market share for each of these suppliers is shown in Figure 8.
The GE 1.5 megawatt turbine was the most commonly installed unit in 2007. Vestas,
Siemens, and Gamesa — European manufacturers with an increasing number of
production facilities in the United States — account for a combined market share
roughly equivalent to that of GE. Suzlon, an Indian manufacturer and the world’s
fifth largest turbine producer, may face new challenges after having to recall many51
of the turbine blades it sold into the U.S. market due to premature cracking. Other
new manufacturers are also entering the field. Clipper Windpower is gaining market
share as manufacturing capacity grows for its new 2.5 megawatt turbines. According
to the Global Wind Energy Council, two Chinese firms, Gold Wind and Sinovel, are
also likely to enter international markets in 2009 with low-cost turbines.
Figure 8. U.S. Wind Turbine Market Share by
Manufacturer in 2007

Gamesa Cl i p p e r1%
11%Su zl on
GE Wind7%
44 %
Ve s t a s
18 %
Source: R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation,
SiemensCost, and Performance Trends, U.S. DOE, p.10.
Because shipping large wind turbine parts is expensive, suppliers build
manufacturing facilities close to where wind plants will be installed. According to
AWEA, wind industry manufacturing facilities in the United States grew from a
small base in 2005 to over 100 in 2007. New wind turbine component manufacturing
facilities opened in Illinois, Iowa, South Dakota, Texas, and Wisconsin in 2007,
while seven other facilities were announced in Arkansas, Colorado, Iowa, North52
Carolina, New York, and Oklahoma. Expanding production and operations in the
United States is especially attractive to European companies given the current value
51 T. Wright, “India Windmill Empire Begins to Show Cracks,” Wall Street Journal, April

18, 2008, P. A1.

52 Wind Power Outlook 2008, AWEA, 2008, p. 4.

of the euro to the dollar. Despite the expansion in turbine manufacturing facilities
in the United States, Europe, and Asia, demand continues to exceed supply.53 The
financial crisis that hit U.S. and global markets in late summer 2008 has at least
temporarily dampened the availability of debt financing for many infrastructure
projects, including wind power, but the long-term impacts remain to be seen.
Most wind plants in the United States are built and operated by independent
power producers (IPPs), also known as merchant providers, that are not regulated
utilities. IPPs have the most flexibility in taking advantage of the renewable tax
incentives since regulated utilities cannot claim the renewable PTC. Still, investor-
owned utilities do build and operate some wind plants; one estimate states that
utilities built just over 10% of the total new capacity in wind electricity in 2007.54
Dozens of companies from around the world develop and operate wind plants
in the United States. Selected examples of active developers and operators in early

2008 include Acciona, AES, Babcock & Brown, Edison Mission, FPL Energy,

Gamesa Energy, Horizon, Invenergy, John Deere, Noble Environmental, PPM
Energy, and RES Americas.55 According to DOE, consolidation among companies
remains strong, including the purchase of Horizon Wind by Energias de Portugal
(from Portugal) and the acquisition of Airtricity North America by E.ON AG (from
Germany). 56
International Comparisons
The United States led the world in wind power deployment until 1996 when it
was surpassed by Germany (Figure 9). Strong U.S. growth in new wind capacity
pushed the United States into the number two spot ahead of Spain in 2007, and the
Global Wind Energy Council (GWEC) expects the United States to become the
world leader in installed capacity again by the end of 2009.57

53 According to one report, in early 2008 General Electric had a backlog of wind turbines
on order equal to $12 billion, more than twice the backlog in early 2007. M. Kanellos, “GE
Confirms That Wind Turbine Supply Is Getting Worse,” CNet, April 13, 2008.
54 R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation, Cost, and
Performance Trends: 2007, DOE, May 2008, p. 15.
55 AWEA 2007 Market Report, AWEA, January 2008, pp. 9-11.
56 R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation, Cost and
Performance Trends: 2007, DOE, May 2008, p. 13.
57 Global Wind 2007 Report, Global Wind Energy Council, 2008, p. 6.

Figure 9. Global Installed Wind Capacity By Country

80,000All Others
60,000 (MIndia
6 97 998 999 000 001 002 003 004 005 006 007
1995 19 9 19 1 1 2 2 2 2 2 2 2 2
Source: Adapted from J. Dorn, "Global Wind Power Capacity Reaches 100,000 Megawatts,"
Earth Policy Institute, March 2004.
As countries deploy increasing quantities of wind capacity, new operational
issues need to be addressed. Grid operators must become accustomed to dealing with
the variability of wind in order to operate the system efficiently and reliably. Despite
the near parity in total wind generating capacity among the top three countries, the
United States has a much lower percentage penetration rate of actual wind power
generation than Denmark, Spain, Portugal, Ireland, and Germany (Table 1). These
European countries have gained experience operating their electricity grids at higher
wind integration rates.
Table 1. Wind Energy Penetration Rates by Country
CountryWind Energy Penetration Rate (%)
United States1
Source: R. Wiser and M. Bolinger, Annual Report on U.S. Wind Power Installation, Cost, and
Performance Trends: 2007, U.S. DOE, May 2008, p. 6.
Note: Wind energy penetration is defined here as the ratio of wind-generated electricity to the total
electricity generated by all sources.

China has the most rapidly growing wind sector in the world, but started from
a very low base. New wind power additions in China are dwarfed by the amount of
new coal-fired power plant construction.58 Chinese leaders are reportedly considering
a new wind power target of 100,000 megawatts by 2020, five-fold the previous
target.59 The German experience with wind power is highlighted in Text Box 3.
In summary, wind technology has evolved over the past two decades, resulting
in larger, more reliable machines. Manufacturing capacity in the United States has
expanded significantly. These advances have led to increasingly competitive wind
electricity costs, the topic of the next section.

58 According to GWEC, installed wind power capacity in China grew by an average annual
rate of 56% between 2001 and 2007. Approximately 3,500 megawatts of new wind were
installed in 2007. (Global Wind 2007 Report, GWEC, April 2008, p. 28.) According to a
statement by Zhang Guobao, Vice Premier of the National Development and Reform
Commission, China installed approximately 70,000 megawatts of new coal-fired generating
capacity in 2007 as reported in Y. Wang, “China May Boost Power Capacity 40% in 3 Years
as Demand Rises,” Bloomberg, May 12, 2008.
59 C. Fu, “Fanning Wind Power Capacity,” Shanghai Daily, April 28, 2008.

Text Box 3. Focus on Wind Power in Germany
Germany is the world leader in installed wind power capacity. Given the country’s
relatively modest wind and solar resources, it has ambitious plans for renewable energy,
including a goal that renewable energy meet 20% of total energy needs by 2020.
The primary driver of wind power growth in Germany is the country’s “feed-in
tariff” policy that gives producers of wind power a guaranteed constant minimum price
over a maximum term of 20 years. The amount of the tariff depends on the location of the
wind turbine and the specific year. The average 2007 payment was about 12.9 U.S.a
cents/kWh and is scheduled to slowly decline to about 10.9 cents/kWh by 2015.
Electricity in Germany is relatively expensive; the wind industry’s impact on overallb
electricity price is not clearly known.
Wind accounts for about 18% of installed capacity and generates 7% of the
country’s electricity. Most of Germany’s wind farms lie in the northern Baltic coast
region where wind resources are superior. Wind plants are widely deployed in Germany
and few onshore areas with good wind resources remain to be developed. The shortage
of onshore sites is leading Germany to replace older, less efficient wind turbines with
larger, more powerful models.
The shortage of high-quality onshore sites is also leading to an expansion of
offshore wind plants. In 2006, the federal government passed a law stating that grid
operators must bear the costs for connecting to offshore wind plants as soon as they are
ready to begin producing power. At the end of 2007, Germany had installed only seven
megawatts of offshore wind generating capacity, although it had hundreds of megawatts
more under development.
The German wind industry is not without critics. As elsewhere, critics state that
wind energy depends on expensive subsidies, especially the feed-in tariff and grid
connection requirements. As Germany is a relatively mature wind user, much of the
countryside is dotted with wind plants. Some Germans oppose the visual impact these
wind plants create and are concerned that they may impact the tourism industry. Finally,
a recent study by the German Energy Agency claimed that wind power is an expensivec
way to lower carbon dioxide emissions compared with other options.

a. German Energy Agency, Planning of the Grid Integration of Wind Energy in Germany Onshore
and Offshore up to the Year 2020, February, 2005. The exchange rate used in this
conversion was 1.55 U.S. dollars per euro.
b. The impact of growing wind use on Germanys electricity prices is obscured by larger
restructuring and liberalization within the sector. B. Odent, “Les factures d’électricité
germaniques se shootent à la libéralisation,l’Humanité, June 29, 2007.
c. Project Steering Group, “Planning of the Grid Integration of Wind Energy in Germany Onshore
and Offshore Up to the Year 2020,” German Energy Agency, March 2005.
Wind Power Economics
Numerous complex variables affect the economics of wind power. This section
includes a financial analysis that compares the cost of building and operating wind
plants with competing technologies (coal, natural gas, and nuclear power). The
financial analysis provides an indicative picture of how the economics of wind

compare with other bulk power sources. A comprehensive analysis for a specific
project would take many other factors into consideration, including the cost of any
necessary transmission upgrades and other options (e.g., purchased power or demand
reduction). The following analysis was conducted before the financial crisis hit in
late summer 2008.
Cost and Operating Characteristics of Wind Power
Wind power is characterized by low variable costs and relatively high fixed
costs. Wind turbines have, of course, no fuel costs, and minimal variable operations
and maintenance (O&M) expense.60 In addition to having no direct expense for fuel,
wind also does not incur the ancillary expenses associated with fossil fuel
combustion, such as air pollution control equipment and allowances needed to
comply with current law and, possibly, future carbon controls. Wind also does not
incur the waste disposal costs associated with conventional generation, such as
scrubber sludge disposal for coal plants and radioactive waste storage for nuclear
As reported in 2005, the initial cost of wind turbines is about half of total wind
plant development costs (Figure 10).61
Figure 10. Component Costs for Typical Wind Plants

In t e r e s t
Con s tructi on 4%
22 % To w ers
10% Connection
De vel op m en t
Tu r b i n e s 4%Fe e s
49% 3%
Tr a n s p o r t Des ig n
2% 2%
Source: National Renewable Energy Laboratory, 2005.
60 Variable O&M costs vary with the output of a generating station, such as the cost of the
consumables used by pollution control equipment. Fixed O&M, which is insensitive to the
level of plant output, includes such costs as the salaries of plant staff and scheduled
61 S. Butterfield, “Fundamentals of Wind Technology,” NREL, presentation at American
Wind Energy Association conference, May 15, 2005.

Although wind plants have low variable costs, the fixed O&M costs are
relatively high, and wind power plants are capital intensive.62 As with other
generation technologies, the cost of building a wind plant has increased in recent
years. The reported unit cost of wind projects constructed in the United States
declined steadily through the 1990s and, according to one study, bottomed out at
about $1,400 per kilowatt of capacity in the 2000-2002 time period.63
Subsequently, project costs have risen steadily and averaged over $1,700 per
kilowatt in 2007. Higher input prices (steel, cooper, concrete), a shortage of skilled
workers, unfavorable currency exchange, and shortages in key wind turbine
components and manufacturing capacity explain much of the overall cost increase.64
Rapidly rising costs have also been experienced by all other utility-scale generation
technologies.65 In the case of wind, some analysts believe that the lapses in the
production tax credit contributed to boom-and-bust cycles in the sector and
discouraged steadier investment in new production capacity.66
Wind Operation and System Integration Issues. Operators try to
maximize the power output from units with high fixed costs so that those costs can
be spread over as many kilowatt-hours of electric generation as possible. This
reduces the average cost of power from the unit and makes the unit’s power more
economical for consumers (and more marketable if the unit is operating in a
competitive market).
Wind plants, however, cannot run as baseload units (i.e., continuously
operating) because generation is subject to wind variability. Like solar power, wind
is a source of variable renewable power that is dependent on daily, seasonal, and
locational variations in the weather. Geographic diversity — that is, installing wind
turbines over a large area — may compensate to some degree for local variations in
wind conditions, but ultimately wind power cannot achieve the same degree of
reliability or continuous operation as fossil or nuclear technology. The combination

62 Capital intensive means that compared to some other generating sources, such as gas-fired
plants, wind plants require a relatively large initial outlay to build the plant. This large
outlay also translates into higher fixed costs, in the form of repayment of the debt portion
of construction financing.
63 These data were gathered by analysts at Lawrence Berkeley National Lab from 227
completed wind projects totaling 12,998 megawatts of capacity. Reported in R. Wiser and
M. Bolinger, Annual Report on U.S. Wind Power Installation, Cost, and Performance
Trends: 2007, U.S. DOE, May 2008, pp. 21.
64 L. Flowers, “Wind Energy Update,” NREL, February 2008.
65 According to Cambridge Energy Research Associates, coal, gas, wind, and nuclear power
plants were, on average, 131% more expensive to build in late 2007 compared to 2000.
Sector-specific cost increases include wind 108%, nuclear 173%, coal 78% and gas 92%.
See “Costs to Build Power Plants Pressure Rates,” Wall Street Journal, May 27, 2008.
66 R. Wiser, M. Bolinger, and G. Barbose, “Using the Production Tax Credit to Build a
Durable Market for Wind Power in the United States,” Lawrence Berkeley National
Laboratory, 2007.

of the relatively low capacity factor of wind plants and high fixed costs drives up the
cost of wind-generated electricity.
The variable nature of wind power has an additional cost implication. Electric
power systems must be able to reliably meet all firm customer loads at all times. For
this reason power systems are built around generating technologies that are
dispatchable and predictable — that is, units that can be reliably turned on or off, or
have their output ramped up or down, as needed to meet changes in load. However,
because a wind turbine is weather dependent it is not dispatchable or as predicable
as a fossil or nuclear unit. As noted previously, energy storage can help address this
shortcoming in wind energy, although it also results in higher costs.
When a power system is dependent on only small amounts of wind generation
to meet load, the variations in wind output can be absorbed by the system’s existing
buffer capacity. This capacity is either fossil fuel, nuclear, or dispatchable renewable
energy (e.g., hydroelectric, geothermal, and biomass). However, when wind
constitutes a large part of the system’s total generating capacity, perhaps 10% to 15%
or greater, the system must incur additional costs to provide reliable backup for the
wind turbines. For example, in 2007 a utility in Montana built a gas-fired plant for
the primary purpose of compensating for wind power variability.67 Various estimates
have been made of the cost of integrating large blocks of wind capacity into a power
system. Estimates for integration costs range from $1.85 to $4.97 per megawatt-
hour.68 In 2008, the Bonneville Power Administration established a wind integration
charge of $2.82 per megawatt-hour.69 (See Text Box 4 below for a description of a
recent system integration issue in Texas.)
In summary, wind power has the economic advantage of zero fuel costs and no
costs for the pollution controls associated with the consumption of fossil and nuclear
fuel. However, wind plants have relatively high fixed costs, and the plants cannot be
operated as intensively as fossil or nuclear plants due to the variability of the wind.
Wind variability also creates system integration costs at high levels of wind
penetration. These cost disadvantages are partly offset by the federal renewable
production tax credit (discussed below) and also, in effect, by state renewable
portfolio standards that mandate the use of renewable power.

67 Mike Mercer, “Power for a Calm Day,” Diesel & Gas Turbine Worldwide, October 2007.
The station is Northwestern Energy’s Basin Creek plant, a 51.8 MW plant consisting of 9
gas-fired diesel generators.
68 B. Parsons, M. Milligan, et al. “Grid Impacts of Wind Power Variability: Recent
Assessments from a Variety of Utilities in the United States,” conference paper presented
at the European Wind Energy Conference. Athens, Greece, 2006 [
docs/fy06osti/39955.pdf], p. 9.
69 This is equivalent to 0.282 cents per kilowatt-hour. Gail Kinsey Hill, “BPA Calculates
Administrative Costs of Wind Power,” The Oregonian, March 29, 2008.

Text Box 4. Electricity Curtailment Event in Texas
A recent event in Texas serves to illustrate the challenge of integrating wind power
into existing electricity grids. At 6:41 p.m. on February 26, 2008, the Electric Reliability
Council of Texas (ERCOT, the manager of most of the electric power grid in Texas)
activated its emergency electric curtailment plan due to low frequency on the electricity
grid. The emergency measure cut power to customers who had agreed in advance to such
action in order to prevent more serious grid problems from occurring. The frequency
drop was caused by an unplanned shortfall in available generation sources (primarily
wind) at the same time demand was increasing. According to ERCOT’s summary report,
wind generator availability dropped from 1,700 megawatts three hours before the event
to about 300 megawatts at the point the emergency procedures were activated.
An action item ERCOT took from the event is to accelerate plans to implement an
improved wind forecasting system. The summary report is available at
[http://interchange n t s / 27706_114_5777


Levelized Cost Comparison
Although wind power is not dispatchable, it is often seen as a replacement or
supplement for conventional baseload power plants. This is because when wind
conditions are favorable a wind turbine is used like a baseload plant: the wind turbine
is run at full load as continuously as possible. The following economic analysis
therefore compares wind power to the primary baseload alternative technologies
using coal, nuclear power, or natural gas. Each technology is described briefly in
Text Box 5.
The generation costs of these technologies and wind power are compared using
the financial analysis technique of levelized costs, which summarizes the estimated
lifetime costs of each system as a levelized (“annualized”) cost per megawatt-hour
of generation. This analysis is for plants entering commercial service in 2015, and
costs are measured in constant 2008 dollars. The financial methodology and the key
assumptions concerning plant costs and operations are described in Appendix A. The
current estimate of “overnight” construction costs for each technology — that is, the
cost that would be incurred if a plant could be built instantly — are summarized
below in Table 2, along with the assumed capacity factor. Table 2 also indicates the
type of entity assumed to build each kind of plant. Coal and nuclear plants are
assumed to be constructed by regulated utilities that have the financial resources and
regulatory support to undertake these very large and expensive projects. The natural
gas combined-cycle plant is assumed to be built by an independent power producer
(IPP). IPPs generally prefer gas-fired projects because of their relatively low capital
costs and risk profiles. The wind plant is also assumed to be an IPP project because
regulated utilities normally cannot make use of the production tax credit.70 Again,

70 Assuming the natural gas combined cycle was built by a utility reduces the estimated cost
in the Base Case by about $4 per megawatt-hour. This is due to the lower financing costs
available to regulated utilities compared to IPPs. If the wind plant is built by a utility the

the estimates in Table 2 do not include the impacts of the financial crisis that began
in late summer 2008.
Text Box 5. Description of Primary Power Generation Technologies
!Conventional (pulverized) coal. This is the conventional technology
used in most existing coal-fired power plants. Coal is ground to a fine
powder, and then burned in a boiler to create steam which drives a
generator. Modern coal plants are equipped with environmental control
equipment that can greatly reduce air emissions, with the exception of
carbon dioxide. No pulverized coal plants — or, for that matter, any
other kind of fossil-fueled power plant — have been built with carbon
control technology.
!Natural Gas Combined Cycle. This is a standard technology widely
used to generate electricity. Natural gas is burned in a combustion
turbine (the same type of technology used in a jet engine) to rotate a
generator and produce electricity. The waste heat, in the form of
exhaust gases, from the combustion turbine is then captured and used
to produce steam, which drives a second generator to produce more
electricity. Combined cycle plants are relatively inexpensive to build
and very efficient, but use expensive natural gas as the fuel.
!Nuclear Power. These plants use heat from nuclear fission to produce
steam for power generation. This report uses projected costs and
performance for next generation nuclear plants characterized, for
example, by simplified designs and modularized construction
Table 2. Assumptions for Generating Technologies
AssumedType of
TechnologyOvernight Cost in 2008 (2008$ per Kilowatt of Capacity)CapacityProject
Wind $1,900 34% IPP
Coal $2,600 85% Utility
Nuclear $3,700 90% Utility
Natural Gas$1,20070%IPP
Sources: Overnight capital costs estimated by CRS based on a review of published information on
recent power projects. Capacity factor for coal plants is from Massachusetts Institute of Technology,
The Future of Coal, 2007, p. 128. Natural gas plants are assumed to operate as baseload units with

70 (...continued)
estimated cost increases by about $1 per megawatt-hour. This is the net effect of the lower
financing costs and the loss of the production tax credits. The renewable production tax
credit applies to sales of electricity by the wind plant owner to another entity. A utility
which operates a wind plant to serve its own load cannot take the credit. See 10 C.F.R. §

a capacity factor of 70%. Capacity factor for wind from California Energy Commission, “Comparative
Costs of California Central Station Electricity Generation Technologies,” December 2007, Appendix
B, p. 67. Nuclear plant capacity factor reflects the recent industry average performance as reported
in EIA, Monthly Energy Review, Table 8.1. Also see Appendix A to this report.
Costs were estimated for six cases intended to illustrate some of the important
economic, operational, and government incentive factors that influence the relative
economics of wind power.71 The Base Case (Case 1) assumes continuation of the
renewable production tax credit as currently formulated. It also assumes the nuclear
plant qualifies for the nuclear production tax credit (at an effective rate of $12 per
megawatt-hour)72 and loan guarantee program established by the Energy Policy Act
of 2005. No carbon costs are assumed. The five alternative cases have the following
characteristics (each is identical to the Base Case except as indicated):
!Case 2: Reduced Incentives. The renewable production tax credit
is assumed to terminate and is not renewed. The nuclear plant is
assumed to not receive a loan guarantee.73
!Case 3: High Natural Gas Prices. Natural gas prices are assumed
to be 50% higher than the current EIA forecast used in the Base
!Case 4: Carbon Costs. This case assumes the imposition of
controls on carbon emissions from fossil fueled power plants. An
illustrative allowance price of $25 per metric ton of carbon dioxide
is assumed, escalating at a real rate of one percent per year, first
imposed in 2013.74
!Case 5: Wind Capacity Factor. This case assumes that the wind
plant has a capacity factor of 44% rather than the 34% used in the
Base Case. The higher capacity factor could be the result of
improved technology or a better-than-average location.75

71 Other factors, combinations of factors, and alternative cost forecasts could be evaluated.
The economic analyses presented here consider just one subset of many potential alternative
assumptions. The subset was chosen to highlight some of the important determinants of the
competitiveness of wind power.
72 The nominal value of the nuclear production tax credit of $18 per megawatt-hour will be
reduced if more than 6,000 megawatts of new nuclear capacity qualify for the credit. The
Base Case follows EIA’s long-term forecast assumption that the effective rate will be
reduced to $12 per megawatt-hour because 9,000 megawatts of new nuclear capacity will
qualify. See EIA, Annual Energy Outlook 2007, pp. 20-21.
73 The status of the renewable PTC is discussed elsewhere in this report.
74 In 2008, the Congressional Budget Office (CBO) estimated the price of carbon dioxide
allowances in 2013 at $30 per metric ton in nominal dollars. Given an estimated change in
the implicit price deflator of 17.2% between 2005 and 2013, this converts to $25.60 per
metric ton in constant 2005 dollars. This value was rounded to $26 per metric ton to
simplify the presentation. See CBO, “Cost Estimate for S. 2191, America’s Climate
Security Act of 2007,” April 10, 2008, p. 8.
75 EIA assumes that a 44% capacity factor would be achievable by 2010 for a wind plant
located in the northwest. The wind capacity factor for this region actually declines over

!Case 6: Wind Integration Cost. A system integration charge is
added to the cost of wind power. The assumed cost is the
Bonneville Power Administration charge of $2.82 per megawatt-
hour. This cost is assumed to remain constant in real dollar terms
for the forecast period.
The results for the six cases are summarized below in Table 3. These estimates
should be viewed as indicative and not definitive, and are subject to a high degree of
uncertainty. As shown in the table:
!In Case 1, the levelized cost of wind power is a few percent higher
than coal or gas-fired power; given the range of uncertainty in the
assumptions, the costs of these options are essentially similar.
Nuclear power, which is assumed to benefit from the full range of
federal incentives (a production tax credit and loan guarantee) is
about 10% less expensive than wind and the least expensive of all
the alternatives examined.
!In Case 2, reducing incentives significantly changes the results. If
the renewable production tax credit is assumed to terminate, the cost
of wind power increases by 10%. In this situation coal and gas have
a 14% to 15% cost advantage over wind. However, the biggest
impact of reducing incentives is on nuclear power. Assuming no
loan guarantee, the cost of nuclear power increases by 28% (from
$60 to $77 per megawatt-hour).76 In this situation, wind power’s
cost (also without a production tax credit) is essentially similar
(slightly lower) than nuclear power.
!Natural gas prices have historically been difficult to forecast and
often underestimated.77 When gas prices are assumed to be 50%

75 (...continued)
time, to 41% by 2030, presumably because wind plants are increasingly located in less
favorable locations. See EIA, Assumptions to the Annual Energy Outlook 2007, Table 73.
Planning consultants to the utility Westar Energy assumed that wind plants located in
Kansas could achieve capacity factors of 42%. See Direct Testimony of Michael Elenbaas
on behalf of Westar Energy, before the Kansas State Corporation Commission, Docket 08-
WSEE-309-PRE, October 1, 2007, pp. 11 and 13.
76 The loan guarantee allows the nuclear plant to be financed with 80% debt at a low interest
rate. In the absence of the loan guarantee the cost of debt increases and the debt portion of
the financial structure drops to 50%. The balance of the financing is equity, which is more
expensive than debt. Eliminating the loan guarantee, therefore, has a major impact on the
cost of a nuclear project. The chief nuclear officer for Exelon, the power company with the
largest fleet of nuclear reactors in the United States, stated that constructing new nuclear
plants will be “impossible” in the absence of loan guarantees (S. Dolley, “Nuclear Power
Key to Exelon’s Low-Carbon Plan,” Nucleonics Week, February 14, 2008). For further
discussion of the importance of loan guarantees, see Tom Tiernan, “Nuclear Interests, Wall
Street Concerned about Loan Guarantee Program, Legislation,” Electric Utility Week,
August 20, 2007. Wind power is not eligible for the loan guarantees provided in EPACT05
because it is not considered a commercial technology.
77 For example, see EIA, Annual Energy Outlook Retrospective Review: Evaluation of

higher than in the Base Case, wind has an 18% cost advantage over
gas-fired electricity (Case 3).
!The imposition of an illustrative cost of $25 per metric ton of carbon
dioxide on fossil-fired generation (Case 4) has the greatest impact on
the relative competitiveness of wind with coal. The carbon cost
takes coal from a 4% cost advantage over wind in the Base Case to
a 19% disadvantage. The impact on gas-fired power is significant,
but less dramatic; gas goes from a 6% cost advantage to a 4%
disadvantage when carbon costs are imposed.78
!As discussed above, the combination of high capital costs and
relatively low utilization rates, as measured by the capacity factor,
creates a cost disadvantage for wind power. The importance of
utilization is illustrated by Case 5, which assumes a wind capacity
factor of 44%, compared to the 34% rate used in the Base Case.
With a high capacity factor, wind has the lowest cost of the
alternatives examined, and in particular is over 25% less costly than
coal or gas.
!The final case (Case 6) assumes the imposition of a system
integration charge of $2.82 per Mwh on wind generation. As Table

5 shows, costs under this case and the Base Case are similar.

In summary, the financial analysis suggests the following:
!Given the Base Case assumptions, including continuation of the
renewable production tax credit, the cost of wind power is
comparable to coal and gas. The addition of an illustrative system
integration charge, to account for large-scale wind penetration of a
utility system, does not greatly change these results.
!Federal financial incentive policies have a significant impact on the
financial analysis. The economics of wind are materially worse
when the production tax credit is eliminated, and materially
improved versus nuclear power when nuclear incentives are
!Improved technology or prime locations that allow wind projects to
achieve high rates of utilization would significantly lower the cost
of wind power.
!Assuming higher natural gas prices than the current EIA reference
forecast, or the imposition of carbon charges on coal and gas, greatly
enhances the cost competitiveness of wind.

77 (...continued)
Projections in Past Editions (1982-2006), pp. 2, 3, and 5.
78 Carbon costs have less impact on the gas plant because gas emits about half as much
carbon dioxide per unit burned than coal, and a combined cycle gas-fired plant requires less
fuel to produce a unit of electricity than a pulverized coal plant.

Table 3. Economic Comparison of Wind Power with Alternatives
(New Plants Entering Commercial Service in 2015,
Levelized 2008$ Per Megawatt-hour and Percent Difference)
Levelized Cost of Power, 2008$ per megawatt-hourWind Cost Advantage (Disadvantage) Comparison,Percent Difference
ePulverizedNatural GasPulverizedNatural Gas
Wind Coal Nuclear CC Coal Nuc l e a r CC
$67 $64 $60 $63 (4%) (10%) ( 6%)
ncentives $74 $64 $77 $63 (14%) 4% ( 15%)
iki/CRS-RL34546gh Natural Gas$67$64$60$79(4%)(10%)18%
s.or $67 $80 $60 $70 19% (10%) 4%
://wikiher Wind Capacity$50$64$60$6328%20%26%
ntegration Cost$69$64$60$63(7%)(13%)(9%)
: See main body of the report and Appendix A.
es: “CC” = Combined Cycle. “PTC” = production tax credit. These estimates are approximations subject to a high degree of uncertainty over such factors as future
he rankings of the technologies by cost are therefore also an approximation and should not be viewed as a definitive estimate of the relative
competitiveness of each option.

Wind Policy Issues
This section of the report discusses government policy issues related to wind
power. Some issues, such as permitting, are primarily state and local issues, but still
may be a concern to congressional constituents. Other issues, such as the extension
of the renewable production tax credit, are clearly federal issues.
Siting and Permitting Issues
Like other electric power projects, wind energy projects built and operated in
the United States must comply with applicable federal, state, and local requirements.
Most wind energy projects in the United States today are built on private land. As a
result, local and state jurisdictions play the most important role in siting and
permitting wind energy projects.79 These projects, however, usually must also meet
certain federal requirements such as those in the Endangered Species Act
(U.S.C.§1531-1544), Migratory Bird Treaty Act (U.S.C.§§703-711), or Hazard
Determination by the Federal Aviation Administration (FAA).80 Key siting and
permitting issues are discussed below.81
Wildlife Constraints. The main environmental objection to wind power is
concern about bird and bat collisions with wind turbines. A National Academy of
Sciences report states that, “Out of a total of perhaps 1 billion birds killed annually
as a result of human structures, vehicles and activities, somewhere between 20,000
and 37,000 died in 2003 as a result of collisions with wind-energy facilities.”82
Although this is a small percentage of total birds killed, the impact on particular
species could be significant, especially if wind power continues to expand rapidly.
Early wind turbines in California killed birds — especially raptors (hunting
birds like hawks, eagles, and owls, some of which are protected under the
Endangered Species Act) — and catalyzed opposition to wind power among bird

79 Energy projects built on private land that receive federal grants or use federal transmission
lines must also meet federal requirements in the National Environmental Policy Act (42
U.S.C. §4321).
80 Others might include the Bald and Golden Eagle Protection Act (16 U.S.C. §§668-668d),
National Historic Preservation Act (16 U.S.C. §470), Clean Water Act (33 U.S.C. §1251),
Rivers and Harbors Act of 1899 (33 U.S.C. §401), Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA or Superfund, 42 U.S.C. §§9601-9675).
81 More comprehensive information on federal, state and local regulations related to wind
energy projects is found in: Energy Efficiency and Renewable Energy, “Federal Wind Siting
Information Center,” DOE [],
Wind Energy Siting Handbook, AWEA, 2008 and Permitting of Wind Energy Facilities: A
Handbook, National Wind Coordinating Committee, Revised 2002.
82 National Research Council, Environmental Impacts of Wind-Energy Projects: Report in
Brief, The National Academy of Sciences, 2007, p. 2.

enthusiasts.83 Although bird concerns remain, today’s turbines kill far fewer birds
per unit of electricity generated than early models, especially in California.84 More
recently, a relatively large number of bat fatalities have occurred at wind plants in
West Virginia, Pennsylvania, New York, Alberta, and elsewhere.85 As a result, the
wind industry and bat supporters formed a new organization, the Bats & Wind
Energy Cooperative (BWEC) to fund studies designed to reduce bat mortality.86
Most experts concede that not enough is known about avian behavior to predict
accurately what the affect on species will be if wind plants continue to expand. More
collaborative study is underway to improve understanding of ways to minimize avian
deaths.87 Potential mitigation options include:
!Stopping wind plants during key migratory periods,
!Painting blades to improve visibility,
!Avoiding locations, such as some mountain passes, already known
to be migration corridors,
!Employing acoustic deterrents, and
!Moving selected turbines.
In addition to birds and bats, wildlife protection experts are studying how wind
plant construction and operation affects terrestrial animals.88 Greater prairie
chickens, for example, shy away from tall structures and may thus avoid living near
wind plants.89
Federal agencies produced interim recommended guidelines in 2003 to assist
project developers in considering and minimizing wildlife impacts.90 The DOI
(through Fish and Wildlife Services, FWS) has established a Wind Turbine

83 These early turbines were not designed with avian populations in mind. The blades spun
much more quickly than today’s turbines and the towers were often constructed of lattice
steel, an enticing nesting feature for birds.
84 Wind Power: Impacts on Wildlife and Government Responsibilities for Regulating
Development and Protecting Wildlife, Government Accountability Office, GAO-05-906,
September 2005, pp. 10-13.
85 J. Layke, K. Porter, and A. Perera, “Diversifying Corporate Energy Purchasing with Wind
Power,” World Resources Institute, February 2008, p. 14.
86 BWEC includes AWEA, Bat Conservation International, the U.S. Fish and Wildlife
Service, and the U.S. Department of Energy’s National Renewable Energy Laboratory.
“Wind Energy and Wildlife: Frequently Asked Questions,” AWEA, 2008, p. 2.
87 See, for example, “Bats and Wind Energy Cooperative” [].
88 See, for example, National Research Council, Environmental Impacts of Wind-Energy
Projects: Report in Brief, The National Academy of Sciences, 2007
89 J. Layke, K. Porter, A. Perera, “Diversifying Corporate Energy Purchasing with Wind
Power,” World Resources Institute, 2008, p. 9.
90 See “Interim Guidelines to Avoid and Minimize Wildlife Impacts from Wind Turbines,”
U.S. Department of the Interior, Fish and Wildlife Service, 2003, [

Guidelines Advisory Committee to advise the Secretary on developing effective
voluntary measures to minimize impacts to wildlife related to land-based wind
turbines.91 Early in the 110th Congress, Title VII of the New Direction for Energy
Independence, National Security, and Consumer Protection Act (H.R. 3221) had
required formation of such a committee, but the provision was removed when the bill
was merged with H.R. 6. As noted previously, Congress gave MMS primary
authority over most aspects of siting off-shore wind plants through EPACT05.
Aesthetic and Social Issues. Some landowners object to the visual impact
that wind turbines create, especially near shore, mountainous, forested, protected, or
other “valuable” areas. They view wind turbines as an unacceptable human or
industrial fingerprint on lands that should remain natural. These objections are
reflected in the offshore Cape Wind project, where opponents argue that natural
“landscapes” (or seascapes, in this case) will be forever altered by the wind turbines.
In addition to the visual impacts, there are other objections. All wind turbines
produce mechanical and aerodynamic noise. Noise is thus a siting criterion for
regulatory purposes. Early wind turbine models were often loud, especially
downwind versions (blades behind the generator). Newer models are designed to
minimize noise.92 Like visual aesthetics, wind turbine noise is often a matter of
individual preferences and tolerances. For residences over 1 kilometer (0.6 miles)
from a wind turbine, noise is generally not an issue.
Shadow flicker, also know as shadow casting or blinking, is defined as
alternating changes in light intensity caused by the moving blades casting shadows
on the ground or objects. No flicker shadow will be cast when the sun is obscured
by clouds or when the turbine is not rotating. This phenomenon can be annoying for
residents who live very close to turbines. Computer simulations can help project
developers position turbines so that flicker does not interfere with nearby residences.
Shadow flicker generally does not affect residences located 10 rotor diameters or
more (about 0.5 miles) from the turbine, except possibly early in the morning or late
in the evening when shadows are long.93
Radar Issues. Wind turbines can interfere with civilian and military radar at
some locations. The potential interference occurs when wind turbines reflect radar
waves and cause ghosting (false readings) or shadowing (dead zones) on receiving94
monitors. Radar interference thus raises national security and safety concerns.

91 The Charter describing the committee’s formation is available on the FWS website at
[ habitatcons erva tion/Advi sory_Committee_Charter_3_20_07.pdf].
92 A. Rogers, J. Manwell, and S. Wright, Wind Turbine Acoustic Noise, University of
Massachusetts at Amherst, Renewable Energy Research Laboratory, June 2002.
93 B. Voll, “Black Springs Wind Farm Shadow Flicker Study,” Energreen Wind, 2006, p.


94 See also M. Brenner, et al., Wind Farms and Radar, The MITRE Corporation, JSR-08-

126, January 2008.

Concern over wind power and radar interference appeared to peak after
Congress enacted the National Defense Authorization Act for Fiscal Year 2006 (P.L.
109-163) on January 3, 2006. Section 358 of the law required the Department of
Defense (DOD) to submit to Congress within 120 days a report on the impacts of
wind plants on military readiness. In response, DOD and the Department of
Homeland Security (DHS) issued a temporary ruling on March 21, 2006, contesting
the construction of any wind plant within radar line of sight of key military radar
facilities until the report could be completed. AWEA stated in a June 2006 fact sheet
that the de facto moratorium on billions of dollars worth of wind investment in parts
of the country was inappropriate.95 The temporary ruling was clarified on July 10,

2006, in a joint DOD-DHS memo to the Federal Aviation Administration (FAA),96

calling for a case-by-case evaluation of the potential of wind projects on radar
systems. Permitting resumed for most of the affected projects later that year.
The DOD impacts report97 concluded that wind farms located within radar line
of sight of an air defense radar have the potential to degrade the ability of that radar
to perform its intended function. It also noted that currently proven mitigation
options to completely prevent any degradation in primary radar performance of air
defense radars are limited to methods that avoid locating wind turbines within their
radar line of sight. DOD has initiated research efforts to develop additional
mitigation approaches that in the future could enable wind turbines to be placed
within radar line of sight of air defense radars without impacting their performance.98
The FAA has oversight over any object that could have an impact on
communications in navigable airspace, either commercial or military. DOD
participates in the FAA review and evaluation of applications for potential impacts
to its ability to defend the nation. The FAA requires that a Notice of Proposed
Construction or Alteration be filed for any project that would extend more than 200
feet above ground level (or less in certain circumstances, for example if the object is
closer than 20,000 feet away from a public-use airport with a runway more than

3,200 feet long).99

Although the DOD report noted limited options to “completely prevent” the
degradation of any performance of air defense radar systems, DOE believes that
practical solutions to radar interference are achievable. DOE notes that in the
majority of cases, interference is either not present, is not deemed significant, or can

95 AWEA, “Wind Turbines and Radar: An Informational Resource,” June 2, 2006
[ h t t p : / / www.awea.or g/ pubs/ f act sheet s / 060602_Wi nd_T ur bi nes_and% 20_Radar _F a c t _ S h
96 K. Kinsmore, and R. Wright, “Intent of March 21, 2006 Memorandum,” Department of
Defense and Department of Homeland Security Joint Program Office, July 10, 2006.
97 The report was issues on September 27, 2006 and is available at [
pubs/pdfs/WindFar mReport.pdf]
98 Office of the Director of Defense Research and Engineering, The Effect of Windmill
Farms on Military Readiness, DOD, September 2006, pp. 56-57.
99 FAA requirements on potential obstructions are discussed at [
external/portal.j sp].

be readily mitigated.100 Potential interference is highly site specific and depends on
local features, type of radar, and wind plant characteristics. In most cases, radar
interference can be corrected with software that deletes radar signals from stationary
Transmission Constraints
Transmission constraints are considered to be one of the biggest challenges
facing the U.S. wind industry.
The electricity grid in the United States is aging and overloaded in some regions,
and new investment is required to ensure reliable, efficient transmission of
electricity.101 Siting new transmission lines is an expensive, time consuming, and,
often, controversial endeavor. Wind plant developers seek access to transmission
capacity that allows them to send their electricity to market without having to build
new lines, especially ones they need to pay for themselves. As noted previously,
much of the nation’s best wind resources are located in remote, lightly populated
areas where little transmission capacity exists. Demand centers, where the electricity
is consumed, can be hundreds of miles away. A 2006 estimate puts the cost of new
transmission lines at $1.5- $2 million per mile, and costs may have increased since.102
Transmission constraints occur in at least 3 ways:
!Limited transmission capacity,
!Scheduling difficulties in using existing lines, and
!Delays in interconnecting new wind power sources to the grid.
Limited Transmission Capacity. Good sites for wind plants may be
located in areas with limited available capacity on the transmission network, or the
sites may be distant from any existing transmission lines. These capacity limits are
the most fundamental constraint facing wind power project developers. It can take
many years to plan and build new infrastructure. Wind plant developers who build
in regions with limited or no transmission capacity may have to incur all construction
costs for new or improved transmission infrastructure, an expensive proposition.
Texas is attempting to address its wind power transmission constraints through
competitive renewable energy zones (CREZs), which attempt to optimize the linking
of promising wind zones with demand centers and overcome the “chicken and egg”
problem between wind plant developers and transmission providers. California is
pursuing a similar CREZ policy, and other states, including New Mexico, Wyoming,

100 U.S. DOE, “Wind Powering America,” available at [
101 See CRS Report RL33875, Electric Transmission: Approaches for Energizing a Sagging
Industry, by Amy Abel.
102 Actual costs are location dependent. Northwest Power Pool, “Canada — Northwest —
California Transmission Options Study,” pp. 16-27, May 16, 2006.

and Colorado, are expanding transmission infrastructure to accommodate wind and
other electricity options.103
Under the Energy Policy Act of 2005 (EPACT05), in certain cases where
transmission congestion exists, the Federal Energy Regulatory Commission (FERC)
may use federal over-ride (eminent domain) authority to site new transmission lines
when states have not acted to site those lines.104 Also under EPACT05, FERC is
authorized to approve a funding plan for new transmission that would charge the new
generator for all costs associated with interconnection rather than socializing the
interconnection costs over all users of the transmission network.105 This type of
funding could be cost prohibitive for small wind facilities.
Finally, EPACT05 also directed FERC to establish incentive rules to encourage
greater investment in the nation’s transmission infrastructure, promote electric power
reliability, and lower costs for consumers by reducing transmission congestion. Order
No. 679 allows a public utility to obtain incentive rate treatment for transmission
infrastructure investments under certain conditions.
Scheduling Difficulties. Transmission scheduling difficulties for wind
power can result because the original rules for access to transmission capacity were
not designed with intermittent sources, like wind, in mind. As the electricity sector
slowly transforms itself from one with several hundred vertically integrated utilities
with their own transmission control areas to one with a combination of regional
transmission organizations (RTOs) and traditional control centers, the rules are being
rewritten. Under the old rules, economic penalties were applied to generators that did
not meet their day-ahead schedule requirements. For wind power, this occurred
frequently since power output varies with wind variability, making scheduling
difficult. Wind developers claim that the old rules discriminated against intermittent
sources. In February 2007, FERC issued Order No. 890 to allow greater access to
transmission lines for power generators of all types, including renewable energy106
Rate pancaking (using the transmission facilities of multiple operators and
incurring access charges from each) is another scheduling barrier for wind power in
some regions. Only large transmission systems acting as a single network resource
allow wind plants to avoid pancaking. FERC tried to promote a Standard Market
Design order in 2002-2003 that might have provided greater uniformity to
transmission pricing, but the effort was dropped due to opposition.107

103 L. Chaset, “Comments of the Public Utility Commission of California,” FERC Docket
No. AD08-2-00, December 11, 2007; and S. Smith, “Wind on the Wires: Can Transmission
Infrastructure Adapt?,” Utility Automation and Engineering T&D, May 2008.
104 P.L. 109-58, §1221.
105 P.L. 109-58, §1242.
106 Preventing Undue Discrimination and Preference in Transmission Service (Order 890),
Federal Energy Regulatory Commission, February 16, 2007.
107 See CRS Report RS21407, Federal Energy Regulatory Commission’s Standard Market

Transmission Interconnection. There are long queues (waiting lists) in
some regions of the country for wind and other power plant developers to get108
approval to interconnect their new facilities with the grid. FERC issued Orders

2003 and 661 to clarify transmission interconnection requirements and help address109

potential discrimination. FERC is also preparing new guidance to help RTOs and
independent system operators (ISOs) improve their queuing methodology.110 As long
as there is a shortage of transmission capacity, however, transmission interconnection
queuing is likely to remain a problem.111
Federal Renewable Transmission Initiatives. Two bills were introduced
in the 110th Congress to address transmission of wind power and other renewable
electricity. The Clean Renewable Energy and Economic Development Act (S. 2076),
introduced in September 2007, would, among other things, amend the Federal Power
Act to require national renewable energy zones. These zones would be specified
areas that have the potential to generate 1,000 megawatts of electricity from
renewable energy, a significant portion of which could be generated in a rural area
or on federal land.
The legislation would also require FERC to promulgate regulations to ensure
that (1) specified public utility transmission providers that finance renewable
electricity connection facilities in such zones recover incurred costs and a reasonable
return on equity associated with the new transmission capacity; and (2) not less than
75% of the capacity of specified high-voltage transmission facilities and lines is used
for electricity from renewable energy. The legislation was referred to the Committee
on Energy and Natural Resources, which held a hearing on transmission issues for
renewable electricity resources on June 17, 2008.112

107 (...continued)
Design Activities, by Amy Abel.
108 According to a recent DOE report, there were 225,000 megawatts of proposed wind
power capacity in interconnection queues within 11 RTO, ISO, and utility regions at the end
of 2007. As noted in the report, being in the queue does not guarantee that a project will be
built; many are at an early stage of development and may never achieve commercial
operations. For comparison, the report noted that about 212,000 megawatts of natural gas,
coal, nuclear, solar, and “other” projects were also in queues. R. Wiser and M. Bolinger,
Annual Report on U.S. Wind Power Installation, Cost and Performance Trends: 2007, U.S.
Department of Energy, May 2008, pp. 9-10.
109 Standardization of Generator Interconnection Agreements and Procedures (Order 2003),
Federal Energy Regulatory Commission, July 24, 2003; Interconnection for Wind Energy
(Order 661), Federal Energy Regulatory Commission, June 2, 2005.
110 Interconnection Queuing Practices (Docket No. AD08-2-000), Federal Energy
Regulatory Commission, March 20, 2008.
111 For more information on recent electricity transmission issues that may relate to wind
power, see CRS Report RL33875, Electric Transmission: Approaches for Energizing a
Sagging Industry, by Amy Abel; and 20% Wind Energy by 2030: Increasing Wind Energy’s
Contribution to U.S. Electricity Supply, U.S. DOE, 2008.
112 Testimony from this hearing is available at [

A similar bill in the House, the Rural Clean Energy Superhighways Act (H.R.
4059), was introduced in November 2007. It would also focus on creating national
renewable energy zones under certain conditions. It requires the President to identify,
and provide public notice of, additional renewable energy trunkline facilities and
network upgrades required to increase substantially the generation of electricity from
renewable energy within each potential zone. It directs FERC to pass regulations to
ensure that a public utility that finances transmission capacity to transmit electricity
from renewable energy from a zone to an electricity consuming area recovers through
transmission service rates all prudently incurred costs and a reasonable return on
equity associated with construction and operation of the new transmission capacity.
It also directs FERC, in specified circumstances, to permit a renewable energy
trunkline built by a public utility located in a zone to be initially funded through
transmission charges imposed upon (1) all the utility’s transmission customers in
advance of significant generation interconnection requests; or (2) all the transmission
customers of a Regional Transmission Organization (RTO) or independent system
operator, if the trunkline is built in an area served by one or the other. Cost allocation
procedures are prescribed for new projects and network upgrades. A federal power
marketing administration, including the Tennessee Valley Authority (TVA), that
owns or operates electric transmission facilities is required to finance a network
upgrade or a renewable energy trunkline facility, if within a certain time frame no
privately or publicly funded entity commits to do so.
Renewable Production Tax Credit
The renewable production tax credit is an incentive to business developers of
wind plants and some other renewable energy projects that produce electricity. For
each kilowatt-hour of energy produced, a developer can apply for a credit against
taxes. In 2007, the credit stood at 2.0 cents per kilowatt-hour for claims against
2006 taxes. On October 3, 2008, the PTC was renewed for one year in the
Emergency Economic Stabilization Act of 2008 until December 31, 2009. According
to industry members, the PTC expirations in 2000, 2002, and 2004 have had a
negative impact on the U.S. wind industry’s ability to invest in new production
facilities efficiently.113
Proponents of extending the credit past 2009 argue that the PTC is merited
because it corrects a market failure by providing economic value for the
environmental benefits of “clean” energy sources. Also, they contend it helps “level
the playing field,” noting that there is an even longer history of federal subsidies for

112 (...continued)
index.cfm?FuseActio n = H e arings .Hearing&Hearing_ID=7344491e-df7f-9a28-80ce-47fe5


113 U.S. Congress, House Committee on Ways and Means, Tax Credits for Electricity
Production from Renewable Sources. Hearing held May 24, 2005. Testimony of Dean
Gosselin, FPL Energy. pp. 25-26. [

conventional energy.114 For example, they point to the percentage depletion
allowance for oil and natural gas that has been in place for many decades.115
Opponents of extending the production tax credit beyond the end of 2009 argue
that generally there are no market failures that warrant special tax subsidies for
particular types of renewable energy technologies. They argue further that subsidies
generally distort the free market and that renewables should not get special treatment
that exempts them from this principle. Also, regarding the concern about the
environmental problems of conventional energy sources, they contend that the most
cost-effective economic policy is to put a tax on the pollution from energy sources
and let the free market make the necessary adjustments. Another argument against
the PTC is that intermittent renewable energy production has a fluctuating nature that
makes it less valuable than energy produced by conventional facilities.
PTC Eligibility: IOUs vs. IPPs. The renewable PTC is not available to
investor owned utilities (IOUs), although utilities do finance and own wind plants.
Typically, independent power producers (IPPs) build, finance, and own wind plants
and sell power to regulated utilities. There are a number of financing mechanisms
where other providers of capital assist with financing wind plants in exchange for a
portion of the tax credits. One question for Congress is whether utilities should
become eligible to receive the PTC. Doing so would allow them to finance wind
plants at a lower cost since the interest rates they pay on debt is lower than what an
IPP pays. This would reduce the cost of wind power. One impact of allowing
utilities to receive the renewable tax credits is that they could become more
competitive at producing wind than IPPs. This could threaten the growth of the
dozens of companies that now build wind plants.
Specific PTC Legislative Options. During the 110th Congress, a variety
of bills sought to extend or modify selected renewable energy and energy efficiency
tax incentives, including wind power. Title IV of the Alternative Minimum Tax and
Extenders Tax Relief Act (S. 2886), which was introduced on April 17, 2008, would
extend eight incentives. Title X of the Foreclosure Prevention Act (H.R. 3221),
which passed the Senate on April 10, 2008, incorporates eight renewable energy and
energy efficiency tax incentives from the Clean Energy Tax Stimulus Act (S. 2821).
The Renewable Energy and Energy Conservation Tax Act (H.R. 5351), which passed
the House on February 27, 2008, includes 16 incentives for renewable energy and
energy efficiency. Features of these bills as they relate to the PTC for wind energy
are summarized in Table 4. For updated status on legislation related to the PTC, see

114 Federal subsidies for conventional energy resources and technologies and for electric
power facilities (including large hydroelectric power plants) have been traced back as far
as the 1920s and 1930s. See DOE (Pacific Northwest Laboratory), An Analysis of Federal
Incentives Used to Stimulate Energy Production, 1980. p. 300. The EIA recently published
the latest in a series on federal energy incentives and subsidies: EIA, Federal Financial
Interventions and Subsidies in Energy Markets 2007, DOE, April 2008.
115 GAO. Petroleum and Ethanol Fuels: Tax Incentives and Related GAO Work.
(GAO/RCED-00-301R) September 25, 2000. The report notes that from 1968 through 2000,
about $150 billion (constant 2000 dollars) worth of tax incentives were provided to support
the oil and natural gas industries.

CRS Report RL33831, Energy Efficiency and Renewable Energy Legislation in the

110th Congress, by Fred Sissine, Lynn Cunningham, and Mark Gurevitz.

Table 4. Selected Wind Power Tax Incentive Bills Compared
SenateH.R. 5984,
H.R. 6049Substituteto H.R.H.R. 3221

6049(S. 2821)

Renewable Energy
Production Tax Credit Extension1 year1 year1 year
Clean Renewable Energy Bonds$2 billion$2 billion$400 million
Revenue Offsets
Offsets from reduced oil and gasyesyesno
On October 3, 2008, the PTC was extended for one year until the end of 2009
in the Emergency Economic Stabilization Act of 2008.
Carbon Constraints and the PTC. Climate change is almost certain to be
an important topic in this and future Congresses. Most proposals call for a cap-and-
trade system to reduce greenhouse gas emissions, although carbon taxes have also
been proposed. Either way of constraining greenhouse gas emissions would create
an effective cost on emissions. As noted in the Economics Section of this report, the
Congressional Budget Office estimated the price of carbon dioxide allowances in S.116
2091 at $30 per metric ton in 2013. While this legislation did not pass, future
versions of legislation are likely to have similar price levels on carbon dioxide
allowances. According to the levelized cost analysis presented earlier, such a price
would make wind power about 19% less expensive than power derived from coal.
Even without the PTC, wind power would be more competitive than coal. For natural
gas, the impact of carbon allowance costs would be less dramatic, although the
levelized cost of wind as modeled here would be noticeably lower than natural gas
power. Congress will need to reconsider the policy goal of the renewable PTC if and
when a carbon constraint is imposed.
Alternatives to the PTC. One alternative to the PTC is the renewable energy
payment system, also known as the feed-in tariff. This policy is widely used in
Europe (see Text Box 1 above for the German experience). It guarantees
interconnection with the electricity grid and a premium price to renewable energy
producers. Financing renewable energy projects under a renewable energy payment
system is reportedly easier since there is a transparent source of revenue for a fixed

116 CBO’s analysis was performed in accordance with S. 2191 (the Lieberman-Warner
Climate Security Act of 2008). See CRS Report RL34515 Climate Change: Comparisons
of S. 2191 as Reported (now S. 3036) with Proposed Boxer Amendment, by Brent Yacobucci
and Larry Parker.

period, usually 20 years. Even in Germany, however, critics claim that feed-in tariffs
can be expensive. A summary of the Renewable Energy Jobs and Security Act,
which incorporates renewable energy payments, was circulated in mid-June 2008.117
Renewable Portfolio Standards
In the late 1990s, many states began to restructure their electric utility industries
to allow for increased competition. Some of these states established an RPS, in part,
as a way to create a continuing role for renewable energy in power production.118 An
RPS requires utilities to provide a minimum percentage of their electricity from
approved renewable energy sources. Some states without a restructured industry also
adopted an RPS. The number of states with an RPS has grown steadily but without
consistency — RPS requirements vary from state to state. In April 2008, FERC
reported that 26 states and the District of Columbia had an RPS in place, collectively
covering about 54% of the national electric load.119 Mandatory state RPS targets
range from a low of 2% to a high of 25% of electricity generation. However, most
targets range from 10% to 20% and are scheduled to be reached between 2010 and


Most states include wind energy as an eligible resource and allow some form of
trading between holders of the “renewable energy credits” that result from operating
wind projects.120 Non-compliance penalties imposed by states range from about 1.0
to 5.5 cents per kilowatt-hour. Many states in the Southeast and Midwest regions do
not have an RPS requirement. Several states have broadened their RPS provisions
to allow certain energy efficiency measures and technologies to help satisfy the
Federal RPS Debate. State RPS action has provided an experience base for
the design of a possible national requirement. Proponents of a federal RPS contend

117 The summary is available at [
Inslee_REJ SA_061808.pdf].
118 Section 210 of the Public Utility Regulatory Policies Act (PURPA) of 1978 had
guaranteed a market for the purchase of electric power produced from small renewable
energy facilities. PURPA let states determine the avoided cost pricing of the electricity
production from renewable energy facilities. The effectiveness of this mechanism lessened
with the advent of electric industry restructuring. Provided that certain conditions are met
in any given state, Section 1253 of the Energy Policy Act of 2005 retrospectively terminates
the PURPA mandatory purchase requirements.
119 Federal Energy Regulatory Commission, Renewable Energy Portfolio Standards (RPS),
DOE. For a map showing the status of state action on RPS, see [
market-oversight/mkt -electric/overvi ew/elec-ovr-rps.pdf].
120 Details about eligible resources and other provisions of state RPS programs are available
from the online Database of State Incentives for Renewable Energy and Energy Efficiency,
[]. See also R. Wiser and G. Barbose, Renewables Portfolio
Standards in the United States — A Status Report with Data Through 2007, Lawrence
Berkeley National Laboratory, April 2008; and A. Selting, The Race for the Green: How
Renewable Portfolio Standards Could Affect U.S. Utility Credit Quality, Standard & Poors,
March 2008.

that a national system of tradable credits would enable retail suppliers in states with
fewer resources to comply at the least cost by purchasing credits from organizations
in states with a surplus of low-cost production. Opponents counter that regional
differences in availability, amount, and types of renewable energy resources would
make a federal RPS costly and unfair.
Efforts to include a federal RPS in the Energy Independence and Security Act
(P.L. 110-140) were unsuccessful. In June 2007, S.Amdt. 1537 to H.R. 6 proposed
a 15% federal RPS. Senate floor action on the proposal triggered a lively debate, but
the amendment was ultimately ruled non-germane. In that debate, opponents argued
that a national RPS would raise retail electricity prices and disadvantage Southeastern
states because they lack sufficient renewable energy resources to meet a 15% RPS
requirement. RPS proponents countered that an Energy Information Administration
(EIA) report indicated that the South has sufficient biomass power potential from
existing plants to meet a 15% RPS without becoming “unusually dependent” on other
regions.121 Further, EIA estimated that the 15% RPS would likely raise retail prices
by slightly less than 1% over the 2005 to 2030 period, but would also be likely to
cause retail natural gas prices to fall slightly over that period. In December 2007, the
House approved H.R. 6 with a 15% RPS, but the Senate dropped the provision under
threat of an Administration veto of the bill. The prospects for another federal RPS
initiative in the 110th Congress are unclear.
Wind power in the United States is growing rapidly. Although it currently
supplies only about 1% of the country’s electricity needs, some states and regions
have a much higher level of wind penetration. Furthermore, the amount of proposed
new wind plants either under construction or waiting to be built is significant, and
could soon make wind the largest source of new power supply at the national level.
Continued expansion of wind power in the United States could be slowed by the
current financial crisis, lack of transmission capacity, or expiration of the federal
renewable production tax credit on December 31, 2009. On the other hand, federalth
policy on climate change, expected by many in the 111 Congress, would likely put
a value on carbon dioxide emissions and give wind power additional advantages
compared to coal- and natural gas-based electricity. Congress will need to carefully
consider the interactive nature of energy and climate legislation when crafting future

121 EIA, Impacts of a 15-Percent Renewable Portfolio Standard, DOE, June 2007. 24 p.

Appendix. Financial Analysis Methodology and
The financial analysis of power plant costs in this report estimates the operating
costs and required capital recovery of each generating technology for an analysis
period 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 annual cost expressed as 2008 present value dollars.122
Similarly, the capital costs for the generating technologies are also converted to
levelized annual payments. An investor-owned utility or independent power project
developer must recover the cost of the investment and a return on the investment,
accounting for income taxes, tax law (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, for example, the assumed
cost of money and the applicable depreciation schedule.
In the case of publicly owned utilities the return on capital is a function of the
interest rate. A “capital recovery factor” reflecting each project’s cost of money is
computed and used to calculate a mortgage-type levelized annual payment.123
Combining the annualized capital cost with the annualized cash flows 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 Tables A-1, A-2,
and A-3, below). Most of these inputs are taken from published sources, such as the

122 Converting a series of cash flows to a financially-equivalent uniform annual payment is
a two-step 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 (the “capital recovery factor”).
For a more detailed discussion of the levelization method see, for example, Chan Park,
Fundamentals of Engineering Economics, 2004, Chapter 6; or Eugene Grant, et al.,th
Principles of Engineering Economy, 6 Ed., 1976, Chapter 7.
123 For additional information on capital charge rates see Hoff Stauffer, “Beware Capital
Charge Rates,” The Electricity Journal, April 2006. The capital recovery factor is
equivalent to the PMT function in the Excel spreadsheet program. 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 Engineeringth
Economy, 6 Ed., 1976, Chapter 4.

Energy Information Administration’s (EIA) assumptions used to produce its 2007
and 2008 long-term energy forecasts. Overnight power plant capital costs — that is,
the cost to construct a plant before financing expenses — are estimated by CRS
based on a review of public information on recent projects.
Government incentives are also an important part of the financial analysis.
EPACT05 created or extended federal incentive programs for coal, nuclear, and
renewable technologies. This study assumes the following incentives:
!A renewable energy production tax credit 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. The Base Case analysis assumes that the tax
credit, which is currently scheduled to expire at the end of 2008, will
be extended (as has happened in the past). The credit is available
only to wind power production that is sold to an unaffiliated third
party. Under most circumstances this requirement effectively limits
the production tax credit to independent power producers. A utility
that owns a wind plant and uses the power to serve its own load
would not qualify.124 The credit is currently available to new wind,
geothermal, and several other renewable energy sources. New solar
energy systems do not qualify, and geothermal systems can take the
production tax credit only if they do not use the renewable
investment tax credit (discussed below).
!A nuclear energy production tax credit for new advanced nuclear
plants of 1.8 cents per kWh. The credit applies to the first eight
years of operation. Unlike the renewable production tax credit
described above, 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 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. For example, EIA assumes in its 2007 Annual
Energy Outlook that 9,000 megawatts of new nuclear capacity
qualifies; in this case the credit amount drops to 1.2 cents per
kWh.125 The Base Case for this study follows EIA in using the 1.2
cent per kWh assumption for the effective value of the credit.
!Loan guarantees for carbon-control technologies, including nuclear
power. Under final Department of Energy (DOE) rules the loan

124 See 10 CFR § 451.4.
125 For a discussion of the credit see EIA, Annual Energy Outlook 2007, p. 21.

guarantees can cover up to 80% of the cost of a project. Guarantees
are made available based on a case-by-case evaluation of applicants
and are dependent on congressional authority (in April 2008, the
Department of Energy announced plans to solicit up to $18.5 billion
in loan guarantee applications for nuclear projects126). Entities
receiving loan guarantees must make a “credit subsidy cost”
payment to the federal treasury that reflects the net anticipated cost
of the guarantee to the government, including a probability of
default. The guarantees are, under current rules, unlikely to be
available to public power entities.127
!Energy Investment Tax Credit. Tax credits under this program are
available to certain renewable energy systems, including solar and
geothermal electricity generation, and some other innovative energy
technologies. Wind energy systems do not qualify. The credit is
10% for systems installed after January 1, 2009. Geothermal
projects that take the investment tax credit cannot take the renewable
production tax credit.128
The results of the analysis are shown in the main body of the report. Note that
these estimates are approximations subject to a high degree of uncertainty over such
factors as future fuel and capital costs. The rankings of the technologies by cost are
therefore also an approximation and should not be viewed as a definitive estimate of
the relative cost-competitiveness of each option. Also note that site-specific factors
would influence an actual developer’s choice of generating technologies. For
example, coal may be less costly if a plant is close to coal mines, and the economics
of wind depend in part on the strength and consistency of the wind in a given area.

126 DOE Announces Plans for Future Loan Guarantee Solicitations, Department of Energy
press release, April 11, 2008. Loan guarantee authority of $18.5 billion for nuclear power
plants is provided by P.L. 110-161.
127 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 C.F.R. § 609 (RIN 1901-AB21), October 4, 2007
[ h t t p : / / www.l gpr ogr a m. e n e r gy. go v/ ke ydoc s .ht ml ] .
128 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,
[ ].

Table A-1. Base Case Financial Factors
ItemValueSources and Notes
Representative Bond Interest Rates
Utility Aa2010: 6.8% When available, interest rates for
2015: 7.0%investment grade bonds with a rating of
2020: 7.0%Baa or higher (i.e., other than high yield
bonds) are Global Insight forecasts.
When Global Insight does not forecastIPP High Yield2010: 9.8%
an interest rate for an investment grade2015: 10.0%
bond the value is estimated based on2020: 10.0%
historical relationships between bond
interest rates (the historical data for thisPublic Power Aaa2010: 5.1%
analysis is from the Global Finance2015: 5.4%
website). High yield interest rates are2020: 5.4%
estimated based on the differential
between Merrill Lynch high yield bondCorporate Aaa2010: 6.3%
indices and corporate Baa rates, as2015: 6.5%
reported by (Wall Street2020: 6.5%
Journal website).
Cost of Equity — Utility14.00%California Energy Commission,
“Comparative Cost of California Cental
Station Electricity GeneratingCost of Equity — IPP15.19%
Technologies,” December 2007, Table 8.
Debt Percent of Capital StructureUtility: 50%Northwest Power and Conservation
IPP: 60%Council, “The Fifth Northwest Electric
Utility or IPP withPower and Conservation Plan,” May
federal loan2005, Table I-1.
guarantee: 80%
POU: 100%
Federal Loan Guarantees
Cost of equity premium for entities1.75 percentageCongressional Budget Office, Nuclear
using 80% financing.pointsPower’s Role in Generating Electricity,
May 2008, web supplement (“The
Methodology Behind the Levelized CostCredit Subsidy Cost12.5% of loan value
Analysis”), Table A-5 and page 9.
Long-Term Inflation Rate (change1.9%Global Insight
in the implicit price deflator)
Composite Federal/State Income38%EIA, National Energy Modeling System
Tax RateDocumentation, Electricity Market
Module, March 2006, p. 85.
Notes: EIA = Energy Information Administration; IOU = Investor Owned Utility; POU = Publicly Owned Utility; IPP
= Independent Power Producer. For a summary of bond rating criteria see [
Bond_Ratings_Definitions.php].High yield refers to bonds with a rating below Baa.

Table A-2. Base Case Fuel and Allowance Price Forecasts
Delivered Fuel Prices, Constant 2008$ perAir Emission Allowance
Million BtusPrice, 2008$ per Allowance
CoalNatural GasNuclear FuelSulfurDioxideNitrogenOxides
2010 $1.93 $7.51 $0.58 $249 $2,636
2020 $1.80 $6.41 $0.67 $1,074 $3,252
2030 $1.87 $7.48 $0.67 $479 $3,360
2040 $1.96 $9.17 $0.65 $158 $3,180
2050 $2.06 $11.24 $0.63 $52 $3,009
Sources: Forecasts are from the assumptions to the Energy Information Administrations 2008 Annual Energy Outlook,
which assumes implementation of current law and regulation. The original values in 2006 dollars were converted to 2008
dollars using the Global Insight forecast of the change in the implicit price deflator. The EIA forecasts are to 2030; the
forecasts are extended to 2050 using the 2025 to 2030 growth rates. The sulfur dioxide and nitrogen oxides allowance
forecasts are for the eastern region of the United States (allowance prices are expected to vary regionally under the Clean
Air Interstate Rule).
Note: Btu = British thermal unit.

Table A-3. Power Plant Technology Assumptions
OvernightHeat Rate for UnitsVariable
Construction CostCapacityEntering Service inO&M Cost,Fixed O&M,Capacity
Energy SourceTechnologyfor Units Entering(Megawatts)2015 (Btus per2008$ per2008$ perFactor
Service in 2015,kWh)MwhMegawatt
2008$ per kilowatt
WindOnshore$1,90050Not Applicable$0.00$30,92134%
Coal Supercritical $2,577 600 8,742 $4.46 $28,100 85%
iki/CRS-RL34546Natural GasCombined$1,1864006,506$1.95$11,93670%
g/wCyc l e
s.orNuclear Generation $3,682 1,350 10,400 $0.48 $69,279 90%
leakIII/ III+
http: Heat rates, O&M costs, and nominal plant capacities are from the assumptions to EIAs 2007 and 2008 Annual Energy Outlooks. Capital cost estimates are based on a CRS
ew of public information on current projects. Capital costs and heat rates are adjusted based on the learning rates used by EIA in the Annual Energy Outlook. EIA costs are adjusted
using Global Insights forecast of the implicit price deflator. Capacity factor for coal plants is from Massachusetts Institute of Technology, The Future of Coal, 2007,
Natural gas plants are assumed to operate as baseload units with a capacity factor of 70%. Capacity factor for wind from California Energy Commission, “Comparative Costs
alifornia Central Station Electricity Generation Technologies,” December 2007, Appendix B, p. 67. Nuclear plant capacity factor reflects the recent industry average performance
ed in EIA, Monthly Energy Review, Table 8.1.
kWh = kilowatt-hour; Mwh = megawatt-hour.