² This paper grew out of research originally undertaken by Chapman with financial support from the Electric Power Research Institute in 1996. (For this reason our hypothetical examples take 1997 as the base year.) The authors thank Heather Rhoads and Ron Lehr for their invaluable assistance. They also thank reviewers Roby Roberts, Russell Smith, Tom “Smitty” Smith, Randy Swisher, Carl Weinberg and Jean Wilson. The content of this Research Report does not necessarily reflect the positions of the reviewers, the Renewable Energy Policy Project, or the REPP Board of Directors.
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³ For example, Princeton Economic Research Inc. estimates energy costs for 1998 wind technology at 4.66 cents/kWh at ridgeline sites with 6.7 meters per second (m/s) average wind speed at 10 meters elevation, and 6.51 cents/kWh for lowland sites with 5.2 m/s winds. PERI expects technology available between 2000 and 2002 to generate power at 3.25 cents/kWh and 4.53 cents/kWh, respectively. Wind Energy Weekly 814 (15 September 1998). These costs are based on and consistent with a recent authoritative source: Electric Power Research Institute and the U.S. Department of Energy, Renewable Energy Technology Characterizations, EPRI TR-109496 (December 1997).
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⁴ Notably the Public Utility Regulatory Policies Act of 1978 (PURPA). PURPA required utilities to purchase energy from certain independent power producers at their avoided (marginal) cost of producing electricity.
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⁵ Federal tax incentives included an energy tax credit of 15 percent and an investment tax credit of 10 percent, and expired at the end of 1985. California’s 25 percent credit against taxes of that state expired after 1986. These credits were on the total installed cost of a wind facility and could be taken in the year of initial operation.
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⁶ To relieve the cost to small power producers of negotiating a purchase contract with a utility, the California Public Utility Commis-sion devised standardized Interim Standard Offer 4 (ISO4) power purchase agreements. These 30-year contracts specified the price (plus inflation) that independent generators would receive for their power during the facility’s first ten years of operation, and pegged prices thereafter to the actual avoided cost. The contracts specified prices that reflected expectations in the early 1980s that oil prices would continue to soar. In 1985, as oil prices plummeted, the CEC discontinued ISO4. As the ten-year period expires and the ISO4 contracts revert to (much lower) actual avoided cost, many California wind developments find their revenue streams constrained.
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⁷ On utility management culture, see Richard F. Hirsh, Technology and Transformation in the American Electric Utility Industry (Cambridge, England: Cambridge University Press, 1989), e.g. pp. 114-120.
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⁸ See, for example, National Wind Coordinating Committee, Wind Energy Environmental Issues, Issue Paper No. 2 (January 1997), at http://nationalwind.org/pubs/wes/wes02.htm, accessed 14 October 1998. Also, 1995 National Avian-Wind Power Planning Meet-ing Proceedings at http://nationalwind.org/pubs/avian95/TOC.htm, accessed 14 October 1998.
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⁹ Capacity data from U.S. Department of Energy, National Energy Information Center at (202) 586-8800.
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¹⁰ Wind Briefing 1: World Beaters — The Danish Wind Industry (Amsterdam: Greenpeace International, 1998).
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¹¹ For purposes of comparison, a recent authoritative source projects a drop in installed costs from $1000/kW in 1997 to $720/kW in 2005 (+10% or -20%). EPRI/DOE, Energy Technology Characterizations, p. 6-13.
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¹² EPRI/DOE projects a drop in operation and maintenance costs from 1.0 cents/kWh in 1997 to 0.5 cents/kWh in 2005 (both figures +20% or -30%). EPRI/DOE, Renewable Energy Technology Characterizations, p. 6-13.
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¹³ For class 4 winds, EPRI/DOE predicts that capacity factors will rise from between 26.2% in 1997 to 35.1% in 2005 (all +5% or -15%). Renewable Energy Technology Characterizations, p. 6-13.
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¹⁴ Personal communication from Randall Swisher, Executive Director, American Wind Energy Association (1998).
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¹⁵ EPRI/DOE projects availability factors of 98% (+1% or -2%) for the entire period considered here. Renewable Energy Technology Characteristics, p. 6-12.
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¹⁶ EPRI/DOE projects electrical losses falling from 5% in 1997 to 4% in 2005. Renewable Energy Technology Characteristics, p. 6-19.
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¹⁷ EPRI/DOE projects array losses falling from 5.0% in 1997 to 4.5% in 2005. The EPRI/DOE analysis also considers losses due to rotor soiling, which they see falling from 7.5% in 1997 to 2.5% in 2005. Overall, EPRI/DOE predicts a fall in total losses (i.e., availability, array, rotor soiling, electrical, control and miscellaneous) from 19.5% in 1997 to 13% in 2005. Renewable Energy Technology Characteristics, p. 6-12, 6-19.
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¹⁸ The area of 30 acres per wind turbine is approximately 48D 2 , where D is the diameter of the turbine blade sweep: for example configurations of 7D x 7D, 4D x 12D, 5D x 10D and 3D x 16D. This is the methodology used by D.L. Elliott et al., An Assessment of the Available Windy Land Area and Wind Energy Potential in the Contiguous United States, Battelle Pacific Northwest Laboratory, PNL-7789/UC-261 (August, 1991).
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¹⁹ Ibid.
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²⁰ EPRI/DOE assumes that land-use payments will fall from 3.0% (+ or -30%) in 1997 to 2.5% (+40% or -30%) in 2005. Renewable Energy Technology Characterizations, p. 6-13.
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²¹ For purposes of comparison, the American Wind Energy Association calculates that installing 30,000 MW of wind nationally by 2010 would avoid the emission of 100 million metric tons of CO₂. AWEA, Wind Energy and Climate Change (1997). The U.S. DOE’s “Five Lab Study” considers future energy and policy scenarios, and states that “it is probably reasonable to estimate that additional wind capacity will be 8-23 GW [8,000 to 23,000 MW] in 2010. This translates into reductions of carbon emissions of 6-20 MtC [million tons of carbon] relative to the BAU [business-as-usual] forecast for 2010.” The study notes that wind penetration and carbon reduction could be much higher (50,000 MW and 28 MtC by 2010) given strong carbon-reduction policies. Interlaboratory Working Group on Energy-Efficient and Low Carbon Technologies, Scenarios of U.S. Carbon Reductions: Potential Impacts of EnergyTechnolgies by 2010 and Beyond (1997), pp. 7.19-7.20.
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²² The Texas Sustainable Energy Development Council, organized by Governor Ann Richards in 1993, sponsored research evaluating the characteristics and distribution of wind, solar, biomass, water, and geothermal energy resources in Texas. The analysis also consid-ered the application of distributed energy systems and the capabilities of the electric transmission system. Virtus Energy Research Associates, Texas Renewable Energy Resource Assessment (Austin, TX: Virtus, 1995). This document is in two forms, a Project Summary and the larger Survey, Overview and Recommendations.
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²³ Texas capacity from U.S. Department of Energy, National Energy Information Center at (202) 586-8800.
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²⁴ U.S. Department of Energy, Energy Information Administration, State Energy Data Report 1993: Consumption Estimates, DOE/EIA-0214( 93)/UC-950 (July 1995); State Energy Price and Expenditure Report 1993, DOE/EIA-0376(93)/UC-950 (December 1995). More recent retail figures are somewhat lower: a retail rate of 5.76 cents/kWh for Central Power & Light Co.; 5.69 cents/kWh for Houston Lighting and Power Co.; and 6.10 cents/kWh for Texas Utilities Electric Co. “Wholesale Market Watch March 1998 Profile,” Public Utilities Fortnightly 136 (15 September 1998), p. 13.
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²⁵ Actually, the difference between retail and wholesale rates consists primarily of additive components such as transmission and distribution costs, wheeling charges and administrative costs. Hence if the cost of wind energy exceeds the wholesale cost of conventional sources, then the use of a multiplier will likely overstate the rate impact of wind, because some of those additive costs will either remain constant, or not rise as fast. We have chosen to apply this generous multiplier to the wind increment as a measure of conservatism. Our approach allows for (and may overstate) extra transmission and wheeling costs, which have otherwise been excluded from this analysis. For example, if wind energy were 1 cent/kWh more costly than conventional energy, the multiplier of 2.5 would add 2.5 cents/kWh to the retail rate for wind. In many cases, we expect that 1.5 cents/kWh would be a generous allowance for incremental transmission and/or wheeling costs.
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²⁶ Demand continues to grow at 5.9% in 1998. Personal communication to Wiese from Tom Smith, Public Citizen, Austin, TX (1998).
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²⁷ Emissions benefits are calculated on the basis of average, not marginal, emissions.
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²⁸ Personal communication from Karl Donahue, Electric Reliability Council of Texas (August 1998).
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