4
Economics of Renewable Electricity

The previous chapters established the availability of renewable resources and outlined the technology options for converting those resources into electricity. This chapter explores the challenges and opportunities for bringing substantial renewable electricity generation to market to serve future U.S. electricity needs. Given the experience with renewables over the past 20–30 years, there is an inherent understanding that the economics of renewables have not been favorable. The economics of renewables is about profitability, and profitability depends on three drivers: (1) the market price or value of renewable electricity; (2) the costs of renewables relative to those of other energy resources; and (3), importantly, policies to promote renewables and environmental goals (particularly climate and energy security policies) that raise costs of using fossil fuels and/or subsidize costs of renewables.

The economic future for renewables depends on how market price, costs, and policy evolve. This chapter examines these drivers, the factors that underlie them, and issues associated with making predictions about them and their effects on the success of renewables in the marketplace. It sets out the fundamentals of the electricity market, explores technical and regional issues that affect renewables economics, and outlines the many entities engaged in renewable generation and what they bring to the table. The chapter concludes by summarizing and analyzing cost estimates for the renewable technologies with the greatest likelihood of contributing significantly to electricity generation in the next decade. The goal is not only to compare the costs of various technology options and how they will evolve over time, but also to clarify how markets and government actions can affect the near-term deployment of renewables.



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4 Economics of Renewable Electricity T he previous chapters established the availability of renewable resources and outlined the technology options for converting those resources into electricity. This chapter explores the challenges and opportunities for bringing substantial renewable electricity generation to market to serve future U.S. electricity needs. Given the experience with renewables over the past 20–30 years, there is an inherent understanding that the economics of renewables have not been favorable. The economics of renewables is about profitability, and profitability depends on three drivers: (1) the market price or value of renewable electricity; (2) the costs of renewables relative to those of other energy resources; and (3), importantly, policies to promote renewables and environmental goals (particularly climate and energy security policies) that raise costs of using fossil fuels and/or subsidize costs of renewables. The economic future for renewables depends on how market price, costs, and policy evolve. This chapter examines these drivers, the factors that underlie them, and issues associated with making predictions about them and their effects on the success of renewables in the marketplace. It sets out the fundamentals of the electricity market, explores technical and regional issues that affect renewables economics, and outlines the many entities engaged in renewable generation and what they bring to the table. The chapter concludes by summarizing and analyzing cost estimates for the renewable technologies with the greatest likelihood of con- tributing significantly to electricity generation in the next decade. The goal is not only to compare the costs of various technology options and how they will evolve over time, but also to clarify how markets and government actions can affect the near-term deployment of renewables. 

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Electricity from Renewable Resources  This chapter focuses on the renewable technologies that are closest to market and for which assessments of current and future costs are thus more readily avail- able. These include biomass, wind, concentrating solar power, solar photovoltaics, and geothermal (hydrothermal), but exclude traditional hydropower, because the potential for future extraction of this resource is limited, as noted in Chapter 2. The chapter also excludes hydrokinetics and enhanced geothermal technolo- gies, which are still in the early stages of technological development. The costs presented here come from the wealth of data obtained from projects built in the recent past. THE VALUE OF RENEWABLES Predicting the economics of future renewable generation involves predicting the cost of generation from alternative sources and the value of electricity delivered to the marketplace. The competitive value would be the wholesale price of electricity for grid scale resources and something close to the retail price of electricity for dis- tributed renewable resources.1 These prices define the value of adding renewables to the mix. The ability to predict electricity price is key to making predictions about future market penetration of renewable sources of electricity. The value of generation from renewables will vary geographically and by time of day, because the marginal generator,2 which sets the electricity price, varies with location and over the course of the day with fluctuations in total electricity demand and available supply. Construction of more transmission facili- ties will increase the value of renewables by reducing transmission constraints between regions with abundant renewable resources and those with abundant load (Vajjhala et al., 2008). 1In his analysis of the value of electricity produced by solar PV installations on household and business rooftops, Severin Borenstein (2008b) points out that, although the value to a consumer of not having to purchase electricity may be the retail price of the purchases avoided, the avoided cost to society from installing PV on one’s rooftop is less than the full retail price, which includes payments for recovery of past costs, including the California Energy crisis, and sunk costs of past high-priced electricity contracts. 2To meet electricity demand at lowest cost, system operators tend to dispatch electricity generators in the order of their variable cost of generation, which includes fuel and operating and maintenance costs. The marginal generator is the last generator, and therefore typically the highest-cost generator, that is dispatched to meet electricity demand at any point in time.

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Economics of Renewable Electricity  The importance of relative costs means that efforts to understand how future expected declines in renewables cost are likely to affect renewables penetration will depend on future predictions of the market price of electricity. An analysis of the accuracy with which past studies from the 1970s and 1980s of several different renewable technologies—including wind, solar photovoltaics (PV), con- centrating solar power (CSP), geothermal, and biomass—predicted future costs and future penetrations finds that these past studies performed reasonably well at predicting future cost declines but did not accurately predict market penetrations (McVeigh et al., 2000). McVeigh’s analysis shows that predictions consistently overestimated the expected retail price of electricity in future years. The renewable technologies included in the study had, for the most part, large reductions in cost over time, but these reductions were matched or exceeded by declines in the real cost of supplying electricity with fossil fuels, and thus renewables did not achieve predicted increases in penetration. This suggests that the challenge of predicting future costs of renewables may be exceeded by the challenge of predicting future market conditions that will confront those technologies, which will be equally if not more important in determining the ability of renewables to penetrate the market. In addition to selling electric energy, most wholesale electricity markets also have an additional source of revenue from capacity payments. Capacity payments are made to encourage some generation to be readily available to meet changes in demand and ensure a high level of reliability in delivered electricity despite unforeseen outages. Requirements for the amount of capacity required vary regionally, but the value directly correlates to the expected performance of the unit when needed for generation. For dispatchable fossil generation and renewables, the capacity value is the highest, usually based on close to 100 percent of the unit’s rated capacity. For other renewables, the capacity value is typically lower to reflect the intermittent availability of the resource. The capacity value of a given renewable technology is regionally specific owing to how the capacity value is determined and the relative alignment between resource and load. Although intermittent, the capacity value of grid-scale solar would typically be higher than that of wind, because there is often better correlation between electricity demand and when the sun is shining. Solar resource availability is more predictable than wind is, though clouds do have a serious impact on solar flux. In a region where the wind resource availability does not correlate well with periods of system load, the capacity value may be as low as 8–10 percent of the rated capacity of the unit (ERCOT, 2007; GE Energy Consulting, 2005). In areas where resource or

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Electricity from Renewable Resources  transmission availability allows for better correlations with load, renewables will qualify for higher capacity payments. Capacity payments do not lower costs, but they affect the economics of renewables, because they provide an additional incen- tive to increase dispatchability. Another source of value for most renewables3 is that their operation typi- cally does not contribute to air pollution through emissions of NOx and SO2 and greenhouse gas (GHG) emissions, particularly emissions of CO2.4 Substitut- ing renewable generation for fossil-fuel generation could reduce air pollution and greenhouse gas emissions. These benefits would depend on the type of fossil generation displaced, the emission controls on the fossil generation, the resulting emissions rate of that fossil generation, and the form of environmental regulation governing pollutants.5 For pollutants subject to an emissions cap, as is the case for SO2 nationally or CO2 in states participating in the Regional Greenhouse Gas Initiative, there will not be reduced emissions or environmental benefits. Emissions caps are both a ceiling and a floor on the level of emissions, as emissions reduc- tions at one facility will be made up by increases at another facility, unless the cap is reduced or is no longer binding, which could occur with a dramatic increase in renewable generation. If emissions are capped and emission trading is allowed, there could be an important effect on emission allowance markets and thus on the costs of electric- ity production from fossil fuels with greater penetration of renewables. Greater use of renewables could reduce demand for emission allowances for SO2 and NOx and other capped pollutants, which could reduce their allowance price. To the extent that renewables displace natural gas, at least initially, this effect is likely to be small for pollutants like SO2 and NOx. However, the effect could be larger for pollutants like CO2 if they were capped, though it is a value that would accrue to everyone who has to purchase allowances and not just to the utility that is adopt- ing more renewables. Most emissions of CO2 from electricity generators in the United States are not capped. Increasing renewables generation to replace fossil-fuel generation 3With the exception of hydrothermal, which emits SO2 and CO2, and biopower, which emits NOx and CO2. 4There are emissions associated with the manufacture of different renewable technologies. These life-cycle effects are discussed in Chapter 5. 5Greater reliance on intermittent renewables like wind or solar could increase the need for spinning reserves from fossil generators, and increased operation of these generators in spinning mode or at less than full capacity could reduce the CO2 and NOx emissions benefits.

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Economics of Renewable Electricity  would reduce CO2 emissions, at least relative to business-as-usual emissions. Iden- tifying the extent of those reductions requires some caution. The effects would vary by location, based on the composition of the existing generation fleet and the types of new non-renewable generators and fuels that might otherwise be put in place to meet future electricity needs. These reductions in CO2 emissions would have value to society, and renewable generators might be able to capture some of that value if they could identify consumers willing to pay a premium for CO2-free electricity or green power. COSTS AND ECONOMICS OF RENEWABLE ELECTRICITY Cost is the principal barrier to the widespread adoption of renewable technolo- gies. Generating electricity using renewable energy technologies is more costly than generating it with fossil fuels, especially coal, which supplies about half of the electricity generated in the United States each year. More transmission infra- structure in key locations would also be required for a dramatic increase in power supplied by renewables. Recent increases in renewables market penetration, par- ticularly new wind power, have largely been in response to policies like the federal renewable energy production tax credit and state renewables portfolio standards. These policies seek to close the cost gap in the short term by subsidizing renew- able generation. By encouraging greater market penetration, these policies enable reductions in long-term costs through increased scale and learning in manufactur- ing and in the use of the technology. To achieve greater market penetration, renewables would have to undergo cost reductions at a rate greater than the rate of cost improvement by technologies that set the market price of electricity, including natural-gas- and coal-fired gen- eration. These reductions might result from major breakthroughs in technology, improvements in manufacturing, or improved operating performance of equip- ment, such as higher capacity factors for wind turbines. Likewise, increases in the costs of fossil generation could have an impact on the relative competitiveness of renewables, though the magnitude might not be as great if cost increases also improved the competitiveness of energy efficiency options and nuclear generation. Estimates abound of present and future costs for particular types of renew- ables and other sources of generation. Comparability of these estimates depends on the underlying assumptions and the types of costs captured in summary mea- sures. The next sections discuss the types of costs associated with constructing and

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Electricity from Renewable Resources  operating renewable generating facilities, important assumptions underlying those costs, and how they can be used to construct summary measures of the cost of supplying energy. Cost Concepts and the Levelized Cost of Energy Developing a particular technology to generate electricity incurs costs for the capi- tal equipment, such as the wind turbine and its tower, or solar panels; the land or property, if necessary for installation; and operating and maintaining the equip- ment. Some costs vary with the amount of electricity generated, and some costs are fixed. When a technology requires a fuel, such as biomass generation (bio- power), the cost of the fuel would be a part of the variable operating and mainte- nance cost. Capital costs do not vary with the amount of electricity generated by the facility and are typically stated in dollars per kilowatt ($/kW). Capital costs gen- erally vary with the size of the facility or installation, with economies of scale or volume discounts on equipment orders favoring larger enterprises. Coal-fired and nuclear generating facilities exhibit economies of scale, and larger plants tend to have lower average cost of generation than smaller plants have. For renewables such as wind and solar PV, economies of scale can be greater at the equipment manufacturing stage than at the electricity-generating site, and increased capacity does not decrease the average cost of generation as much as it does for fossil and nuclear plants. Capital costs can also vary across sites, depending on land cost and the costs of installation or construction of the facility. Fixed operating and maintenance (O&M) costs are also stated in dollars per kilowatt, but unlike capital costs, they are an ongoing expense associated with some unit of time ($/kW-year). Typically technologies are characterized by their annual fixed O&M costs. This category includes costs such as wages, materials, and land lease payments. Variable O&M costs are typically expressed as dollars per megawatt-hour ($/MWh). Fuel costs can be expressed as dollars per unit of mass of the fuel ($/ton), dollars per unit of heat content of the fuel ($/Btu), or $/MWh. The last formula takes into account the efficiency of the technology in converting British thermal units (Btu) of heat input into megawatt-hours (MWh) of electricity. In comparing the costs of generating electricity for different renewable tech- nologies and for fossil fuels and nuclear technologies, cost estimates are typically converted into a levelized cost of energy (LCOE), which is expressed in $/MWh.

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Economics of Renewable Electricity  The initial cost of the capital equipment and installation constitutes a large por- tion of the cost of generating electricity, particularly for renewables, which have no fuel costs, with the exception of biopower generation. Converting this large up-front cost to cost per megawatt-hour requires making assumptions about the lifetime and capacity factor of the equipment,6 as well as the discount rate and the timing of returns on that capital. For intermittent technologies such as CSP, solar PV, and wind power, the capacity factor can vary considerably, depending on the location and the quality of the resource (e.g., wind speed and constancy for wind turbines, and hours of sunlight with no cloud cover for CSP and PV); likewise, the LCOE will vary depending on the capacity factor at a particular installation and location. The cost of fuel plays an important role in calculating levelized cost for bio- power. Biopower is typically a baseload technology with a high capacity factor. On an annual basis its fixed equipment costs could be recovered over many hours of operation. However, the hours of operation and the amount of electricity gen- erated by biopower would depend on the cost of fuel, which accounts for about one-third of the total LCOE from biopower (Venkataraman et al., 2007). The cost of biomass fuel is uncertain and would depend on competing demands for crops and other agricultural inputs, including demands for biofuels from the transporta- tion sector. Costs Beyond Generator Costs The costs of purchasing, installing, and operating a specific power plant might not be the total costs to the system and to electricity consumers of deploying a new renewable generation facility. Costs that might be missing from the traditional levelized cost measure include the costs of new infrastructure necessary to connect the renewable generator to the grid and to ensure continued quality of power sup- ply. Other costs include up-front costs for approval of siting the new facility and costs for appraising the resource at the site, as well as costs of obtaining financing and environmental permits.7 6The capacity factor is defined as the ratio (expressed as a percent) of the electricity output of a plant to the electricity that could be produced if the plant operated at its nameplate capacity. 7Levelized cost estimates also typically exclude the costs of the ultimate disposal of the gen- eration equipment at the end of its useful life. Disposal may be complicated and costly for some types of equipment that contain hazardous chemicals that require special disposal procedures.

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Electricity from Renewable Resources 0 Transmission While fossil fuels may be transported from the mine or the wellhead to an electric generation facility, renewable generating plants must be located at or near the resource. There might be some degree of greater flexibility in location for bio- power, but not much. It can be costly to ship biomass fuels, given the relatively low energy density compared to fossil fuels. Thus, biopower facilities are typically located close to sources of fuel. Wind and some solar resources often are located at some distance from the existing transmission grid, and would require new transmission lines to transport the power to the centers of electricity demand or load. As with any new genera- tion, the cost of constructing additional transmission lines should be included in the cost of supplying electricity from renewable resources. A recent report looked at 40 transmission studies covering a broad geographic area on the costs associ- ated with the transmission requirements for wind power (Mills and Wiser, 2009). The transmission costs associated with wind ranged from $0 to $1500/kW, and the majority were less than or equal to $500/kW, with a median of $300/kW. These numbers correspond to $0–79/MWh, with the majority below $25/MWh, and a median of $15/MWh. Intermittent renewables generation requires an addi- tional consideration. Because of low capacity factors, dedicated transmission lines sized to transmit the full amount of power produced during peak generation hours would be unused or underused some of the time. Siting additional peaking capac- ity along a new transmission corridor could potentially leverage the available transmission capacity during periods of underuse by the renewables. A caveat to the preceding discussion is that distributed renewables, such as distributed PV, might end up closer to the load than conventional generation and could lead to less need for investment in transmission. To really achieve substan- tial benefits in terms of avoiding investment in transmission infrastructure may require substantial amounts of distributed renewables investment in particular locations. Intermittency At sufficiently high capacities of solar and wind generation, the costs of intermit- tency could extend beyond costs associated with dedicated transmission facilities to affect the operation of the interconnected transmission grid. More generation from intermittent resources will require additional or alternative resources to help track load, provide voltage support, and meet needs for capacity reserves.

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Economics of Renewable Electricity  These include demand for second-by-second electricity load balancing service, or regulation; load following within the hour; and unit commitment of genera- tors to be available at particular times of the day or week. Renewable electricity must be used when generated because the electricity can be generated only when the resource is available. Typically, fossil-fuel generators that are easily dispatch- able, such as natural gas combustion turbines, supply these ancillary services. As renewables generation increases and fossil generators are curtailed, renewable generation technologies themselves or additional system assets, such as storage, will be needed to meet the increased need for ancillary services, at some additional cost. When system managers have improved tools and technology for predicting resource availability, it will be easier to determine the need for additional genera- tion resources to back up intermittent renewables. Smart Grid technologies, which allow system managers to manage supply and demand in real time, could also mitigate some of the costs of renewable intermittency. An upgrade and expansion of the electricity grid will be necessary no matter what happens with renewables, given the age of the grid and the anticipated growth in electricity demand. Studies in the past five years looked at the costs of integrating wind into the grid, as summarized in Figure 4.1 (Smith, 2007; Wiser and Bolinger, 2008). These 6 BPA — 2002 Total Operating Cost Impact (Dollars per Megawatt-hour) GRE — 2003 5 Xcel-UWIG — May 2003 We Energies — June 2003 PacifiCorp — 2005 Xcel PSCo — April 2006 4 CA-RPS — 2006 3 2 1 0 0 5 10 15 20 25 30 35 Percent Wind Capacity Penetration FIGURE 4.1  Summary of wind plant ancillary services costs from various studies looking  at the cost of regulation service, load following, unit commitment, and natural gas. R 4.1 Source: Developed from data in Smith (2007) and in Wiser and Bolinger (2008).

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Electricity from Renewable Resources  studies examined the costs of regulation service, load following, unit commitment, and natural gas and found that the incremental costs per megawatt-hour range from about $1.50 to almost $5.00. A study on using wind to serve 50 percent of demand showed that the incremental costs are $10–20/MWh, including transmis- sion, storage, and backup generation (DeCarolis and Keith, 2004). The European Wind Energy Association conducted a study of more than 180 sources and deter- mined that additional costs range from $1.50 to $10.20/MWh for market penetra- tion levels of 10 percent and from $2.80 to $11.50 for higher penetration levels (EWEA, 2005). Typically the predicted costs are higher in studies that focus on higher market penetration of wind. In the studies on different levels of penetra- tion, the costs were higher with the higher levels of penetration, but the incremen- tal effect of increased penetration varied across studies. Generally, where the aver- age cost of wind generation would be about $80/MWh, the impact of grid integra- tion costs appeared to be less than 15 percent where wind produced 20 percent or less of total electricity generation. Energy Storage Energy storage could mitigate the impact of intermittent renewables. Today there is very little storage in the United States, as high costs, low efficiencies, and tech- nological uncertainty precluded storage from becoming economically viable.8 Costs for battery and other storage technologies are generally about two to five times higher than the cost target that would make them competitive (less than about $200/kWh for a 4-hour system) (Rastler, 2008). However, technologies might be called on in the future to store electricity generated from intermittent renewable resources if their combined market penetration would rise to 20 percent and beyond. Efficient, cost-effective energy storage could promote grid-scale renewable electricity. Wind and solar system operators have limited control over the amount and timing of power generation, and their production does not line up well with demand requirements. Storage would allow a grid operator to align the dispatch curve with the demand curve, a process referred to as load shifting. In addition to generating revenue when the wholesale market is at its peak, the ability to draw 8The exception is pumped hydroelectric storage, of which there was 21,461 MW of capacity nationwide in 2006 (EIA, 2007a). However, it is widely acknowledged that there is little chance for additional pumped storage because most of the viable pumped hydro opportunities have been exhausted. For this reason, this section omits pumped storage.

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Economics of Renewable Electricity  on storage would obviate the need for some peaker generators at the margin. Stor- age would also alleviate the reliability concerns associated with wind and solar. When renewables provide less than forecasted output, the operator has to turn to the spot market or bring on idle combined cycle natural gas generators to make up the difference. Conversely, when renewables provide too much power, those holding day-ahead gas contracts might not realize the value of their contracts. The market penalizes renewables for this uncertainty and, while recent studies have shown that this might not matter until intermittent renewables reach penetration levels in excess of 20 percent, this uncertainty may have to be addressed if they are to extend any further (DOE, 2008). Storage would also mitigate some site limitations of renewable electricity and help reduce the size and increase the utilization of transmission lines installed for renewable sources. Small-scale domestic storage could also change the economics of distributed wind and solar generation, providing homes with energy security while perhaps making it possible to sell stored energy or capacity back to the grid. As plug-in hybrid electric vehicles (PHEVs) become a reality, households could store the energy they generate right on their vehicles. The National Renewable Energy Laboratory (NREL) found that PHEVs could enable increased penetration of wind energy (Short and Denholm, 2006). Figure 4.2 displays how some of these storage technologies compare in terms of cost of energy and cost of power. At the grid-scale level (greater than 10 MW), compressed air energy storage (CAES) appears to be the most economical now, though the practicality of CAES also depends on the availability of suitable sites. Iowa Energy Storage Park (IESP), a 268 MW system, is scheduled to come on line in Iowa in 2011. Projected costs for IESP are $200–250 million, or $746–933/kW, and the system is designed to go from idle to full output in under 15 minutes. The Texas State Energy Conservation Office estimated total overnight capital costs of a new CAES system at $605/kW. Development and fixed O&M costs were listed at $28.00/kW and $14.07/kW, respectively, and variable O&M costs were estimated to be $1.50/MWh (Ridge Energy Storage, 2005). Batteries are modular and non- site specific, which makes them ideal for distributed generation. The quick, cheap response time also makes batteries ideal for providing backup power, or uninter- ruptible power supply (UPS). Yet despite broad application in other sectors, bat- teries are still very expensive, as shown in Figure 4.2.

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Electricity from Renewable Resources  Palmer, K., D. Burtraw, and J.S. Shih. 2007. The benefits and costs of reducing emissions from the electricity sector. Journal of Environmental Management 83:1. Patel, S. 2009. PV sales in the U.S. soar as solar panel prices plummet. Power Magazine, March 1. Rastler, D. 2008. Electric energy storage briefing. Presentation at the fourth meeting of the Panel on Electricity from Renewable Resources, March 11, 2008. Washington, D.C. Ridge Energy Storage and Grid Services, L.P. 2005. The Economic Impact of CAES of Wind in TX, OK, and NM. Final Report for Texas State Energy Conservation Office, Austin, Tex. June 27. Royal Academy of Engineering. 2004. The Costs of Generating Electricity. London. SEIA (Solar Energy Industries Association). 2004. Our Solar Power Future—The U.S. Photovoltaic Industry Roadmap Through 2030 and Beyond. Washington, D.C. Sheehan, G., and S. Hetznecker. 2008. Utility Scale Solar Power. IEEE Power & Energy Magazine 5 (October). Short, W., and P. Denholm. 2006. A Preliminary Assessment of Plug-in Hybrid Electric Vehicles on Wind Energy Markets. NREL Technical Report. Golden, Colo.: National Renewable Energy Laboratory. April. Smith, J.C. 2007. Integrating wind into the grid. Presentation to the America’s Energy Future Panel on Electricity from Renewable Resources, Washington, D.C. December 7. Smith, R.K. 2006. EIA geothermal supply curve. Memorandum. Washington, D.C.: U.S. Department of Energy, EIA. September 15. Surek, T. 2005. Crystal growth and materials research in photovoltaics: Progress and chal- lenges. Journal of Crystal Growth 275:292-304. Swezey, B., J. Aabakken, and L. Bird. 2007. A Preliminary Examination of the Supply and Demand Balance for Renewable Electricity. NREL/TP-670-42266. Golden, Colo.: National Renewable Energy Laboratory. October. Vajjhala, S., A. Paul, R. Sweeney, and K. Palmer. 2008. Green corridors: Linking interre- gional transmission expansion and renewable energy policies. Discussion Paper 08-06. Washington, D.C.: Resources for the Future, Inc. March. Venkataraman, S., D. Nikas, and T. Pratt. 2007. Which power generation technologies will take the lead in response to carbon controls? S&P Credit Research. New York: Standard and Poor’s. May 11. WGA (Western Governors’ Association). 2006a. Clean and Diversified Energy Initiative: Geothermal Task Force Report. Denver, Colo. WGA. 2006b. Clean and Diversified Energy Initiative: Solar Task Force Report. Denver, Colo. Wiser, R. 2008. The development, deployment, and policy context of renewable electricity: A focus on wind. Presentation at the fourth meeting of the Panel on Electricity from Renewable Resources, March 11, 2008. Washington, D.C.

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Economics of Renewable Electricity  Wiser, R., and G. Barbose. 2008. Renewables Portfolio Standards in the United States: A Status Report with Data Through 2007. Berkeley, Calif.: Lawrence Berkeley National Laboratory. Wiser, R., and M. Bolinger. 2008. Annual Report on U.S. Wind Power Installation, Cost and Performance Trends: 2007. DOE/GO-102008-2590. Washington, D.C.: U.S. Department of Energy.

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Electricity from Renewable Resources  ANNEx TABLE 4.A.1 Current Cost Assumptions for Renewable Technologies (in 2007 Dollars) Overnight Capital Cost ($/kW)a Technology Source Case/Scenario Biopower Biopower–IGCC EIA (2008d) Input table 3766 Biopower–Stoker EPRI (2007a) 3520 Biopower–50 MW fluidized bed EPRI (2007a) PRI 3629 Biopower Venkataraman et al. 2596 (2007) Concentrating Solar Power Concentrating solar NREL (2007) Program 3645 Concentrating solar EIA (2008d) Reference 5021 Concentrating solar EPRI (2007b) Limited and full portfolio Concentrating solar–trough EPRI (2007a) 3271 Concentrating solar Venkataraman et al. 4153 (2007) Concentrating solar–trough ASES (2007) Photovoltaic Photovoltaic NREL (2007) Program 4050 Photovoltaic–distributed EPRI (2007b) Limited and full portfolio Photovoltaic flat plate EPRI (2007a) 5487 Photovoltaic 2-axis EPRI (2007a) 8876 Photovoltaic–distributed SEIA (2004) Baseline Photovoltaic–distributed SEIA (2004) Roadmap Photovoltaic–central EIA (2008d) Input table 6038

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Economics of Renewable Electricity  Variable O&M (+ Fuel Costs ) Fixed O&M Levelized Cost of Energy ($/kWh)b,c Capacity Factor (%) ($/MWh) ($/kW) 6.71 (+ $15)d 83 64.45 0.080 3.74 (+ $35)e 0.0977b,f 85 91.79 4.26 (+ $35)e 0.101b,f 85 94.49 7.27 (+ $28)e 85 166.13 0.090 0.071g 65 8.10 0.00 31 0.00 56.7 0.200 34 0.170 60.2f 34 0.00 0.130 43 31.20 34.3 0.170 0.160–0.190 0.220g 21 0.00 10.4 0.260 0.251b,f 25 0.00 19.5 0.330b,f 32 0.00 46.6 0.150 0.080 22 0.00 11.7 0.320 continued

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Electricity from Renewable Resources  TABLE 4.A.1 Continued Overnight Capital Cost ($/kW)a Technology Source Case/Scenario Wind Onshore wind EIA (2008d) Input table 1923 Onshore wind NREL (2007) Baseline 1052 Onshore wind NREL (2007) Program 927 Onshore wind EPRI (2007b) Limited and full portfolio Onshore wind EPRI (2007a) Class 6, 100 MW 1820 Onshore wind Venkataraman et al. 1765 (2007) Onshore wind Black & Veatch 20% wind energy 1713 (2007) study Onshore wind Midwest ISO MTEP 2008 reference 1983 Offshore wind EIA (2008d) Input table 3851 Offshore wind Black & Veatch 20% wind energy 2388 (2007) study Conventional Pulverized coal EIA (2008d) Input table 2058 Conventional gas combined cycle EIA (2008d) Input table 962 Conventional combustion turbine EIA (2008d) Input table 670 a Fuel cost per megawatt-hour reported by source. b Calculated from inputs based on a 20-year economic life and real cost of capital of 7.5 percent. c Levelized costs here are generic and do not include site-specific development costs or cost of facilitating delivery. d Fuel cost imputed from AEO 2009 Early Release model solution. AEO 2009 Energy Prices (2007$/million Btu) in 2012 are $1.91 for coal, $6.63 for natural gas, and $1.96 for biomass. e Fuel cost per megawatt-hour imputed from EPRI summer study levelized cost and TAG specifications for CFB biomass plant. f This estimate comes from a personal communication with Steve Gehl of EPRI. g EERE numbers are for 2010. h Depending on wind class.

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Economics of Renewable Electricity  Variable O&M (+ Fuel Costs ) Fixed O&M Levelized Cost of Energy ($/kWh)b,c Capacity Factor (%) ($/MWh) ($/kW) 0.069c 36 0.00 30.3 0.033g 45 0.00 26.2 0.029g 46 0.00 25.3 32.5 0.100 0.068b,f 42 0.00 72.7 0.073c 33 0.00 26.0 35–50h 0.064–0.047c,h 5.70 11.9 0.071c 34 0.00 16.5 0.157c 34 0.00 89.5 37–52h 0.094–0.071c,h 15.60 18.7 4.64 (+ $16.7)d 85 27.53 0.050 2.09 (+ $45.1)d 87 12.48 0.060 3.60 (+ $69.3)d 30 12.11 0.100

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Electricity from Renewable Resources 0 TABLE 4.A.2 2020 Cost Projections and Comparisons (in 2007 Dollars) Overnight Cost Capacity (/kW)a Technology Source Case/Scenario Factor (%) Conventional Sources Pulverized coal EIA (2008d) Reference 1985 85 IGCC EIA (2008d) Reference 2233 85 IGCC with sequestration EIA (2008d) Reference 3171 85 Combined cycle EIA (2008d) Reference 928 87 Advanced combined cycle EIA (2008d) Reference 892 87 Advanced combined cycle with EIA (2008d) Reference 1729 87 sequestration Combustion turbine EIA (2008d) Reference 647 30 Advanced combustion turbine EIA (2008d) Reference 587 30 Renewables Biopower Biopower EIA (2008d) Reference 3390 83 Biopower–Stoker EPRI (2007b) Full portfolio 85 Biopower–Stoker EPRI (2007b) Limited portfolio 85 Biopower ASES (2007) WGA Biomass Task 90 Force Geothermal Geothermal EIA (2008d) Reference 1585 90 Concentrating Solar Concentrating solar NREL (2007) Program case 2860 72 Concentrating solar EIA (2008d) Reference 4130 31 Concentrating solar EPRI (2007b) Limited portfolio 34 Concentrating solar EPRI (2007b) Full portfolio 34 Photovoltaic Photovoltaic NREL (2007) Program 2547 21 Photovoltaic EPRI (2007b) Full portfolio Photovoltaic EPRI (2007b) Limited portfolio

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Economics of Renewable Electricity  Total Variable O&M/ Levelized Cost Levelized Cost Capital Cost Fuel Costs Fixed O&M Transmission of Energy ($/kWh)b ($/kW) ($/MWh) ($/MWh) ($/MWh) Cost ($/MWh) 195 52.30 23.06 3.70 3.61 0.083 [0.079] 219 60.64 18.59 5.19 3.61 0.088 [0.084] 311 69.54 23.26 6.19 4.01 0.103 [0.099] 91 18.63 59.21 1.64 3.88 0.083 [0.079] 88 17.98 55.46 1.54 3.88 0.079 [0.075] 170 34.64 68.84 2.61 3.93 0.110 [0.106] 63 33.55 88.49 4.61 11.41 0.138 [0.127] 58 30.71 75.21 4.01 11.41 0.121 [0.110] 333 61.62 22.81 8.86 4.14 0.097 [0.093] 0.096 0.101 ~0.080c 156 75.44 0.00 22.22 5.00 0.103 [0.098] 4.47 0.00 0.050 405 180.02 0.00 21.30 11.00 0.212 [0.201] 0.170 <0.083c 250 135.81 0.00 5.59 0.141 0.220 0.260 continued

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Electricity from Renewable Resources  TABLE 4.A.2 Continued Overnight Cost Capacity (/kW)a Technology Source Case/Scenario Factor (%) Photovoltaic EIA (2008d) Reference 5185 22 Photovoltaic–distributed SEIA (2004) Baseline Photovoltaic–distributed SEIA (2004) Roadmap Photovoltaic–distributed ACES (2007) DOE’s Solar 2.50/Wp installed America Initiative cost Wind Onshore wind EIA (2008d) Reference 1896 35 Onshore wind NREL (2007) Baseline 1076 46 Onshore wind NREL (2007) Program 916 49 Onshore wind EPRI (2007b) Full portfolio 42 Onshore wind EPRI (2007b) Limited portfolio 33 Onshore wind Black & Veatch DOE 20% wind 1630 38–52 (2007); DOE (2008) study (depending on wind class) Offshore wind EIA (2008d) Reference 3552 33 Offshore wind Black & Veatch DOE 20% wind 2232 38–52 (2007); DOE (2008) study (depending on wind class) Note: Reflects the base capital cost from AEO 2009 (EIA, 2008d), Table 39, adjusted for learning. This figure does not reflect taxes and depreciation, which are included in the total capital cost. aThe overnight cost includes the effects of technological learning but does not include other project costs, which are reflected in the levelized cost estimated. b [ ] contain AEO estimates of busbar levelized cost of energy, i.e., without transmission-related costs. c Cost estimate is for 2015. d Interpolated between reported targets for 2015 and 2030. Source: Based on data in ASES (2007); Black & Veatch (2007); EIA (2008d); EPRI (2007b); NREL (2007); and SEIA (2004).

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Economics of Renewable Electricity  Total Variable O&M/ Levelized Cost Levelized Cost Capital Cost Fuel Costs Fixed O&M Transmission of Energy ($/kWh)b ($/kW) ($/MWh) ($/MWh) ($/MWh) Cost ($/MWh) 509 292.84 0.00 6.21 13.69 0.313 [0.299] 0.110 0.050 0.075–0.010d 186 81.38 0.00 9.95 8.66 0.100 [0.091] 0.00 27.10 0.033 0.00 23.40 0.027 0.078 0.097 160 48.04–35.1 4.85 3.64–2.66 0.057–0.043 348 154.36 0.00 26.72 9.31 0.191 [0.181] 219 64.1–46.29 4.87–3.52 4.62–3.33 0.074–0.053

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