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-scale 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 of 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. In 1999, the U.S. industry began a period of rapid expansion, slowed occasionally by expiring federal incentives. Strong growth continues to this day, but whether that growth will continue in the face of the current financial crisis is unclear. Wind power is no longer an "alternative" source of energy in many regions of the country. 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 than doubled. Only the amount of new natural gas-fired generating capacity installed during this period exceeded that of wind. 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. 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. Only Germany, with 22,247 megawatts, has more wind power capacity than the United States. 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, state renewable portfolio standards (RPS), 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. 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. 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 power. A key challenge for wind energy is that electricity production depends on when and how consistently winds blow rather than when consumers most need power. This variability can create added expenses and complexity in balancing supply and demand on the grid. Several recent studies note that system integration costs do not become significant ($3 to $5 per megawatt-hour) until wind turbines account for 15-30% of the capacity in a control area. These apparently modest cost estimates have yet to be confirmed within the context of the U.S. electricity system. Another concern is that new transmission infrastructure may be required to send the wind-generated power to where it is needed. This can be an expensive and time-consuming effort. There are 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. 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. (See the section on " Transmission Constraints " for more on this issue.) 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. 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. 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. Wind turbines have no direct emissions of air pollutants, including oxides of sulfur and nitrogen, mercury, particulates, and carbon dioxide. 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. Given rising prices for coal, natural gas, and nuclear fuel, power suppliers are drawn to the certainty that wind—while variable—is inexhaustible and has no fuel cost. By displacing coal-fired and gas-fired generation, wind power would reduce the demand for these fuels, perhaps moderating future prices and price volatility. Wind plants can catalyze rural development because farmers and ranchers receive royalty payments from wind developers who lease their land; the vast majority remains available for crops or grazing. Farmers and ranchers typically receive from project developers $2,000-5,000 per year for each turbine on their land. The land taken out of production for wind turbine pads, access roads, and ancillary equipment reduces income for corn farmers, for example, by about $165 per turbine. Wind energy provides an additional source of revenue for local governments in the form of property taxes on wind plant owners. Wind 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. 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 before its expiration in December 2008. It is unclear how many U.S. jobs are at risk if traditional power plants are not built. 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. Unequal solar heating of the Earth's atmosphere and oceans creates wind. 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 a traditional power plant. This report focuses only on large, utility-scale wind turbines. Smaller, off-grid wind power applications are also growing rapidly, although their aggregate impact is limited. The evolution of wind power technology and market development has been influenced by three physical relationships. First, a wind turbine's power output varies with the cube of wind speed. 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 Southwest. 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 ). "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. 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. 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. The U.S. Great Plains states contain most of the best onshore wind resources. 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. The U.S. Department of the Interior (DOI) estimates that over 90,000 megawatts of wind resource potential lies off the coasts of New England 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. 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). During the 109 th Congress, 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 industry. MMS released a Draft Environmental Impact Statement (EIS) for the Cape 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. wind projects have been proposed in Delaware (Bluewater) and Texas (Galveston). 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 congressional policy, both in research and development funding, and through regulatory frameworks that influence market behavior. 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. 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. 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. 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. 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. 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. 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 later. 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 the " 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% to 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 factor 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. Future advances in wind turbine technology are likely to be evolutionary rather than revolutionary. According to the NREL, which carries out much of DOE's wind research and 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. 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, 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. 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. 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 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. 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. 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 many 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. 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, North Carolina, New York, and Oklahoma. Expanding production and operations in the United States is especially attractive to European companies given the current value 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. 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. 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. 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). 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. 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. 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. Chinese leaders are reportedly considering a new wind power target of 100,000 megawatts by 2020, five-fold the previous target. 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. 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. 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. 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 plants. As reported in 2005, the initial cost of wind turbines is about half of total wind plant development costs ( Figure 10 ). Although wind plants have low variable costs, the fixed O&M costs are relatively high, and wind power plants are capital intensive. 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. 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. Rapidly rising costs have also been experienced by all other utility-scale generation technologies. 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. 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 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. 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. In 2008, the Bonneville Power Administration established a wind integration charge of $2.82 per megawatt-hour. (See Text Box 4 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. 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 the Appendix . 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 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. Again, the estimates in Table 2 do not include the impacts of the financial crisis that began in late summer 2008. 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. 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) 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. 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. 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. 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. 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 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). 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. When gas prices are assumed to be 50% 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. 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 reduced. 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. 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. 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. 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). Key siting and permitting issues are discussed below. 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." 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 enthusiasts. Although bird concerns remain, today's turbines kill far fewer birds per unit of electricity generated than early models, especially in California. More recently, a relatively large number of bat fatalities have occurred at wind plants in West Virginia, Pennsylvania, New York, Alberta, and elsewhere. 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. 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. 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. Greater prairie chickens, for example, shy away from tall structures and may thus avoid living near wind plants. Federal agencies produced interim recommended guidelines in 2003 to assist project developers in considering and minimizing wildlife impacts. The DOI (through Fish and Wildlife Services, FWS) has established a Wind Turbine Guidelines Advisory Committee to advise the Secretary on developing effective voluntary measures to minimize impacts to wildlife related to land-based wind turbines. Early in the 110 th 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 the Energy Policy Act of 2005 (EPACT05). 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. 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. 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 receiving monitors. Radar interference thus raises national security and safety concerns. 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. The temporary ruling was clarified on July 10, 2006, in a joint DOD-DHS memo to the FAA, 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 report 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. 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). 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 be readily mitigated. 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 targets. 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. 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. 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. 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, and Colorado, are expanding transmission infrastructure to accommodate wind and other electricity options. Under 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. 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. 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. 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 energy projects. 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. There are long queues (waiting lists) in some regions of the country for wind and other power plant developers to get approval to interconnect their new facilities with the grid. FERC issued Orders 2003 and 661 to clarify transmission interconnection requirements and help address potential discrimination. FERC is also preparing new guidance to help RTOs and independent system operators (ISOs) improve their queuing methodology. As long as there is a shortage of transmission capacity, however, transmission interconnection queuing is likely to remain a problem. Two bills were introduced in the 110 th 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. 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 an 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, 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. 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. 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 conventional energy. For example, they point to the percentage depletion allowance for oil and natural gas that has been in place for many decades. 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. 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. During the 110 th 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 CRS Report RL33831, Energy Efficiency and Renewable Energy Legislation in the 110 th Congress , by [author name scrubbed], [author name scrubbed], and [author name scrubbed]. On October 3, 2008, the PTC was extended for one year until the end of 2009 in the Emergency Economic Stabilization Act of 2008. 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. 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. 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 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 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. 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. 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. 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 2025. 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. 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 requirement. State RPS action has provided an experience base for the design of a possible national requirement. Proponents of a federal RPS contend 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 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. 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 110 th 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, federal policy on climate change, expected by many in the 111 th 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 policy. 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. 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. 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 Table A-1 , Table A-2 , and Table A-3 ). Most of these inputs are taken from published sources, such as EIA's 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. 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. 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 DOE rules, the loan 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 projects ). 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. 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. 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.

Summary: 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.