Wind

2003 capacity additions
Cost overview
Cost factors
Recent costs
Where the wind blows
Wind power integration
Wind turbine technology
Wind power business models
Wind power information

Most wind power costs are incurred as an outlay of up-front capital (installed capital cost, also called first costs), followed by fairly predictable future payments of debt-service, land-use payments, fixed O&M, and so on. Capital costs vary considerably by project, due to choice of specific technology, site characteristics (such as the ease of digging for pouring foundations), any necessary substation upgrades, and other factors. According to the National Wind Coordinating Committee, installed capital cost makes up about 70 percent of the levelized cost of a kilowatt-hour of wind power. Consequently, it is the primary focus of efforts to improve the economics of wind power by developing higher-efficiency and more inexpensively installed equipment. The industry rule of thumb for first costs is about $800 to $1,000 per kilowatt ($1 million per megawatt) depending on the size of the turbine and the site characteristics, but this cost continues to fall.

Operations and Maintenance

Wind power's operation and maintenance costs include all those annually recurring costs involved in routine operation of the wind facility. According to the National Wind Coordinating Committee, unscheduled maintenance, statistically predictable on an annual basis, constitutes about 16 percent of the total cost of a kilowatt-hour, and scheduled preventive maintenance makes up another 4 percent (Table 1). Other O&M costs, making up the balance of overall costs, include taxes, land-use payments, insurance, transmission access, wheeling fees, and staff and management costs.

Table 1: Comparison of Estimated Cost of Energy Components

Source: National Wind Coordinating Committee's Wind Energy Costs

O&M costs are decreasing as the reliability and sophistication of each new generation of turbines increase. But data on this new equipment is scarce. In 1997, the Council estimated O&M costs at 1.3¢ per kWh. But a more detailed U.S. Department of Energy study using data projections for 2005 estimated these costs to be 0.5¢ per kWh. A more recent estimate from the Danish Wind Turbine Manufacturers Association asserts that O&M costs for new machines installed in that country are around 1.0¢ per kWh. Using historical and current data, a reasonable O&M assumption is 0.6¢ to 1.2¢ per kWh over the next few years.

For more information on the cost components of wind operation and maintenance, see the Danish Wind Industry Association's section on O&M costs.

Financing and Project Ownership

Because the bulk of wind power's cost occurs up front (that is, in the form of capital rather than operating or fuel costs), how that capital is supplied strongly influences the overall costs.

Until recently, wind projects in the United States were perceived to be high risk, clouded by the 1996 bankruptcy of turbine manufacturer U.S. Wind Power, the inconsistent performance of first-generation technology, and concern about of widespread avian mortality. Now, however, wind power is proving to be a reliable source of competitive and quickly installed power, demand is increasing, and financing rates for wind projects are coming down. Also, lenders and investors are more likely to have confidence in a wind project if it is undertaken in response to a regulatory mandate such as an renewable portfolio standard, which obligates utilities to purchase wind-generated electricity.

The predominant utility investment model for wind power calls for buying wind-generated electricity through a purchase agreement from an independent power provider (the wind developer or plant owner), which is responsible for obtaining project financing. In general, however, public power companies (such as rural electric cooperatives and municipal utilities) have access to the lowest-cost capital, as they can sell tax-free bonds. Investor-owned utilities usually pay somewhat more for capital, and independent power producers pay the most (as they are seen as a riskier loan recipient). More information on the ownership structure impact on financing is found in the Buy vs. Build section.

Wind quality availability

One vital development decision that greatly affects the final cost of a kilowatt-hour of wind-generated electricity is where to put the turbines. Quite simply, stronger and more constant wind resources produce more electricity per dollar of installed capacity. Because the power generated is roughly equal to the cube of the wind's speed as indicated by the wind turbine power curve, even a small increase in the average wind speed means a large increase in output and corresponding decrease in the kilowatt-hour cost. The American Wind Energy Association estimates that, when average annual wind speed increases from 16 to 21 miles per hour, it reduces production costs by 46 percent (from 4.8¢ to 2.6¢ per kWh in the AWEA example).

For more information and a visual representation of the relationship between wind resource and prices, see Wind Energy Economics from the Danish Wind Industry Association.

Just as important as long-term resource estimates for determining the value of wind power is the ability to predict wind on a short-term basis. Using wind forecasting models to predict short-term availability for power supply scheduling purposes decreases the costs to the utility associated with inefficient or unnecessary balancing reserve and minimizes potential supply imbalance penalties in competitive markets.

Transmission Proximity

One potential trade-off for wind developers is passing up excellent wind resources too remotely located for economic transmission in favor of more moderate resources near existing transmission infrastructure. Although most wind plants have to upgrade existing transmission to some degree, extensive construction of new lines or substations upgrades can be very expensive, and render some projects unprofitable. Typically, the developer is responsible for transmission upgrades and extensions, and those capital costs will be reflected in the contracted purchase price.

Depending on the distance between the wind plant and the power purchaser, compound wheeling fees ("pancaked fees") may also be incurred from sending power through multiple utility control areas on its way to end users. These costs can range from 0.2¢ to 1.0¢ per kWh depending on distance and individual utility rates. Costs that exceed the upper limit of this range usually aren't economical.

For current information on transmission costs and transmission cost modeling, contact Brian Parsons, project manager for Wind Applications, at the National Renewable Energy Laboratory .

Integration costs

Of significant concern to utilities and system operators are the operational and cost impacts of integrating wind power into the electrical delivery system. These are mostly the costs for providing the reserves that must be available to ensure real-time load demands and scheduled power supply are met when the wind isn't blowing. These costs are especially of concern in areas where wind power is a growing percentage of the generation mix—or where there are abundant wind resources with potential for development.

The Utility Wind Interest Group has released a summary report, Wind Power Impacts on Electric-Power-System Operating Costs, which includes results from studies conducted on the power systems of Xcel Energy, Bonneville Power Administration, PJM, We energies and others. The study results, which are linked to the penetration of wind on a given system, show a range of $1.47/MWh for 7 percent penetration in BPA's system to a high of $5.50/MWH for much higher penetration of 20 percent in PacifiCorp's system. The report also addresses integration issues that still warrant investigation.

Source: Wind Power Impacts on Electric-Power-System Operating Costs Summary and Perspective on Work Done to Date November 2003, Utility Wind Interest Group

Turbine and Project Size

The average size of wind plants is increasing partly because the economics favor larger installations. According to American Wind Energy Association, the price of electricity generated in 2001 from a 3-MW plant vs. a 51-MW plant differs by 39 percent (5.9¢ per kWh versus 3.6¢ per kWh in the example given), all else being equal.

These savings come from spreading many of the fixed project costs, such as siting, permitting, construction, power purchase arrangements, and transmission access, across a larger number of kilowatt-hours. Larger wind farms also benefit from having O&M-related costs such as semiannual maintenance visits, surveillance, and administration spread over more turbines.

It is also possible to get similar scale economies from multiple sites installed with a few megawatts each, according to AWEA's Jim Caldwell. Using aggregated purchasing and installation services—or a single developer installing on multiple sites—it is no more expensive, says Caldwell, to develop 20 2-MW installations than one 40-MW project. Because a few turbines can link right into the local distribution grid, some transmission-related costs can also be avoided: transmission extensions or upgrades and the fees for wheeling power through other utilities' transmission lines. For more information on the costs and benefits of this model, see Key Project Decisions.

Larger turbines are integral to increasing overall capacity and creating better wind plant economics. Today the most commonly installed turbine is 1.5 MW, up from less than 1 MW a couple of years ago. And larger turbines must be installed on higher towers, which expose the turbines to stronger and more consistent wind resources farther above ground level.

Land-use Payments

Land-use payments, also called leasing fees, are typically a very small percentage of the overall costs of wind power—about 2 to 3 percent of gross revenue, or $2,000 to $3,000 per turbine per year. But these fees are not inconsequential for the rural landowners (very often farmers) on whose land the turbines are installed, and the local economic and tax-base benefits of a wind farm are attractive incentives in many rural areas.

As competition increases for the best—or best remaining—wind resources, the costs of these land leases may increase as landowners have greater bargaining power. For example, in recent wind power proposals to the state of California, where good wind resources are limited compared with other parts of the country and where landowners are savvy about the value of these resources, land lease cost estimates ranged from 4 percent to 7.5 percent of anticipated gross revenues. Nonetheless, land-use fees will continue to make up a minor portion of the levellized cost for quite some time.

Federal and State incentives

Wind power, like most renewable energy sources, owes much of its current market viability and commercial development to state and federal government funding incentives. Below is a list of major incentives affecting wind development. American Wind Energy Association lists incentives for wind by state. The Database for State Incentives for Renewable Energy provides a state-by-state comprehensive listing of government and utility incentives for the promotion of renewable energy development.

For more detailed information on each of these incentives, see Federal and State Incentives.

Production Tax Credit. A federal PTC of 1.8¢/kWh is currently available for wind energy generation built and operating as of December 2003. All wind energy generated by private companies is eligible for the PTC during the first 10 years of operation. The tax credit, more than any other financial incentive, is responsible for the growth trajectory of wind power development.

Renewable Energy Production Incentive. This is the production tax credit equivalent for qualifying government-owned tax-exempt facilities investing capital in renewable energy. Wind power is one of the primary recipients of this funding source. Although equal in amount to the production tax credit, the Renewable Eneryg Production Incentive is conditional on annual appropriations and is often not factored into cost estimates or projections for publicly owned wind generation. To date, all eligible wind generation has received the REPI; however, it is uncertain whether the supply of these funds will continue to meet growing demand, and many public utilities view this as "ancillary income" rather than a "bankable" incentive.

Systems Benefits Charges. Collected as a non-bypassable surcharge at the state or utility level, the distribution of these funds varies by state and in form. In California, private wind developers are eligible for SBC funds called Production Incentives, which are auctioned to the lowest bidders among interested developers.

Renewable Portfolio Standard. An RPS is a state mandate that obligates retail electricity providers to include a predetermined minimum amount of existing or new renewables in their generation mix through direct ownership of generation, wholesale purchase from another facility, or tradable credits. A Texas RPS requiring the installation of 2,000 MW of new renewables by 2009 has already led to the installation of well over 1,000 MW of generation by the end of 2003. This "overcompliance" has occurred because developers' bids for wind energy proved to be cost-competitive with other resource options—in large part because of the PTC.

Modified Acceleration Cost Recovery System. Out of the U.S. Federal Tax Reform Act of 1986, MACRS allows a 5-year depreciation schedule for wind projects, which compares favorably with the 15- to 20-year schedule allowed for investments in nonrenewable generation projects.