Assumption to the Annual Energy Outlook

Renewable Fuels Module

The NEMS Renewable Fuels Module (RFM) provides natural resources supply and technology input information for forecasts of new central-station U.S. electricity generating capacity using renewable energy resources. The RFM has five submodules representing various renewable energy sources, biomass, geothermal, landfill gas, solar, and wind; a sixth renewable, conventional hydroelectric power, is represented in the Electricity Market Module (EMM).¹⁰⁹

Some renewables, such as landfill gas (LFG) from municipal solid waste (MSW) and other biomass materials, are fuels in the conventional sense of the word, while others, such as wind and solar radiation, are energy sources that do not involve the production or consumption of a fuel.  Renewable technologies cover the gamut of commercial market penetration, from hydroelectric power, which was an original source of electricity generation, to newer power systems using biomass, geothermal, LFG, solar, and wind energy.  In some cases, they require technological innovation to become cost effective or have inherent characteristics, such as intermittency, which make their penetration into the electricity grid dependent upon new methods for integration within utility system plans or upon low-cost energy storage. 

The submodules of the RFM interact primarily with the Electricity Market Module (EMM).  Because of the high level of integration with the EMM, the final outputs (levels of consumption and market penetration over time) for renewable energy technologies are largely dependent upon the EMM.   

Projections for residential and commercial grid-connected photovoltaic systems are developed in the end-use demand modules and not in the RFM; see the Distributed Generation and Combined Heat and Power descriptions in the “Commercial Demand Module” section of the report. 

Key Assumptions 

Nonelectric Renewable Energy Uses 

In addition to projections for renewable energy used in central station electricity generation, the AEO2004 contains projections of nonelectric renewable energy uses for industrial and residential wood consumption, solar residential and commercial hot water heating, blending in transportation fuels, and residential and commercial geothermal (ground-source) heat pumps. Assumptions for their projections are found in the residential, commercial, industrial, and petroleum marketing sections of this report.  Additional minor renewable energy applications occurring outside energy markets, such as direct solar thermal industrial applications or direct lighting, off-grid electricity generation, and heat from geothermal resources used directly (e.g., district heating and greenhouses) are not included in the projections. 

Electric Power Generation 

Table 72. Overnight Capital Cost Characteristics for Renewable Energy Generating Technologies in Four Cases (2002$/kW) Printer Friendly Version     Technology    Total Overnight Costs1       Overnight Costs in  2003        Reference     Low Renewable     High Renewable  DOE Goals  Year  Geothermal2  2,003                     2005  1,882  1,699  1,851  1,746         2010  1,685  1,890  1,509  1,174          2025  2,293   2,524  1,951  1,452  Landfill Gas3  1,475                2005  1,470  1,470  1,470  1,470      2010  1,454  1,454  1,454  1,454      2025  1,404  1,404  1,404  1,404  Photovoltaic4  3,961                2005  3,889  3,981  2,838  3,370      2010  3,684  9,934  2,582  1,743      2025  2,677  3,702  1,817  1,155  Solar Thermal4    2,625                2005     2,577     2,625  2,553  3,004      2010     2,458     2,625  2,374  3,091      2025     2,062     2,577  1,804  2,898  Biomass5  1,731                2005  1,715  1,869  1,818  1,688      2010  1,672  1,869  1,690  1,590      2025  1,460  1,869  1,234  1,287  Wind  1,015                2005   1,010    1,015  1,010  977      2010   1,008    1,015  1,008  888      2025   998    1,015  986  873

Table 73. Capacity Factors1 for Renewable Energy Generating Technologies in Four Cases Printer Friendly Version Technology        Year  Reference  Low Renewables  High Renewables  DOE Goals  Geothermal2  2005  0.86  0.86  0.86  0.86    2010  0.87  0.87  0.87  0.87    2025  0.87  0.87  0.87  0.85              Landfill Gas  2005  0.90  0.90  0.90  0.90    2010  0.90  0.90  0.90  0.90    2025  0.90  0.90  0.90  0.90              Photovoltaic  2005  0.24  0.24  0.24  0.24    2010  0.24  0.24  0.24  0.24    2025  0.24  0.24  0.24  0.24              Solar Thermal  2005  0.15  0.15  0.15  0.19    2010  0.15  0.15  0.15  0.23    2025  0.15  0.15  0.15  0.28              Biomass  2005  0.83  0.83  0.83  0.80    2010  0.83  0.83  0.83  0.80    2025  0.83  0.83  0.83  0.80              Wind  2005  0.39  0.37  0.41  0.41    2010  0.39  0.38  0.41  0.46    2005  0.41  0.38  0.43  0.48

The RFM considers only grid-connected central station electricity generation. The RFM submodules that interact with the EMM are the central station grid-connected biomass, geothermal, landfill gas, solar (thermal and photovoltaic), and wind submodules, which provide specific data or estimates that characterize that resource.  A set of technology cost and performance values is provided directly to the EMM and are central to the build and dispatch decisions of the EMM. The technology cost and performance values are summarized in Table 38 in the chapter discussing the EMM. Overnight capital costs are presented in Table 72 and the assumed capacity factors for new plants in Table 73. 

 Conventional Hydroelectricity 

The Hydroelectric Power Data File in the EMM represents reported plans for new conventional hydroelectric power capacity connected to the transmission grid and reported on Form EIA-860, Annual Electric Generator Report, and Form EIA-867, Annual Nonutility Power Producer Report.  It does not estimate pumped storage hydroelectric capacity, which is considered a storage medium for coal and nuclear power and not a renewable energy use. However, the EMM allows new conventional hydroelectric capacity to be built in addition to reported plans. Converting Idaho National Engineering and Environmental Laboratory information on U.S. hydroelectric potential, the EMM contains regional conventional hydroelectric supply estimates at increasing capital costs.  All the capacity is assumed available at a uniform capacity factor of 45 percent.  Data maintained for hydropower include the available capacity, capacity factors, and costs (capital, and fixed and variable operating and maintenance).  The fossil-fuel heat rate equivalents for hydropower are provided to the report writer for energy consumption calculation purposes only. Because of hydroelectric power’s position in the merit order of generation, it is assumed that all available installed hydroelectric capacity will be used within the constraints of available water supply and general operating requirements (including environmental regulations). 

Capital Costs 

The capital costs of renewable energy technologies are modified to represent two phenomena: 

• Short-term cost adjustment factors, which  increase technology capital costs as a result of a rapid U.S.buildup in a single year, reflecting limitations on the infrastructure (for example, limits on manufacturing, resource assessment, and construction expertise) to accommodate unexpected demand growth. These short-term factors are invoked when  demand for new capacity in any year exceeds 50 percent of the prior year’s total U.S. capacity. For every 1 percent increase in total U.S. capacity over the previous year exceeding 50 percent, capital costs rise 0.5 percent for wind, 0.33 percent for biomass, and 1 percent for solar technologies.   
• For geothermal and wind, higher costs are assumed to result from large cumulative increases in their use, reflecting any or all of three factors: (1)  resource degradation, (2) required transmission network upgrades, and (3 ) competition with other market uses. Presumably, the best  resources are used first. Increased use results in the application of less efficient resources (e.g., less accessible, less productive, more difficult to use (e.g, land roughness, slope, terrain variability, or productivity, wind turbulence or wind variability)). Second, as capacity increases, especially for intermittent technologies like wind power, existing local and long-distance transmission networks require upgrading, increasing overall costs. Third, market pressures from competing land uses increase costs as cumulative capacity increases, including competition from agricultural or other production alternatives, residential or recreational use, aesthetics, or from broader environmental preferences. As a result, each EMM region’s wind resource estimates are parceled into five cost levels, 0, 20, 50, 100 and 200 percent, respectively. For geothermal, four successive increments incur neither, either, or both of 33 percent increases in the drilling and field cost portions of capital costs and doubling of the relatively small exploration cost component. The size of the resource cost increments varies by technology and region. 

For a description of NEMS algorithms lowering generating technologies’ capital costs as more units enter service (learning), see  “Technological Optimism and Learning” in the EMM chapter of this report.  A detailed description of the RFM is provided in the EIA publication, Renewable Fuels Module of the National Energy Modeling System, Model Documentation 2004, DOE/EIA-M069(2004) (Washington, DC, 2004). 

Solar Electric Submodule 

Background 

The Solar Electric Submodule (SOLES) currently includes both concentrating solar power (thermal) and photovoltaics, including two solar technologies:  50 megawatt central receiver (power tower) solar thermal (ST) and 5 megawatt single axis tracking-flat plate thin-film copper-indium-diselenide (CIS) photovoltaic (PV) technologies. PV is assumed available in all thirteen EMM regions, while ST is available only in the six  Western regions where direct normal solar insolation is sufficient. Capital costs for both technologies are determined by EIA using multiple sources, including 1997 technology characterizations by the Department of Energy’s Office of Energy Efficiency and Renewable Energy and the Electric Power Research Institute (EPRI).¹¹⁰ Most other cost and performance characteristics for ST are obtained or derived from the August 6, 1993, California Energy Commission memorandum, Technology Characterization for ER 94; and, for PV, from the Electric Power Research Institute, Technical Assessment Guide (TAG) 1993. In addition, capacity factors are obtained from information provided by the National Renewable Energy Laboratory (NREL). 

Assumptions 

• Capacity factors for solar technologies are assumed to vary by time of day and season of the year, such that nine separate capacity factors are provided for each modeled region, three for time of day and for each of three broad seasonal groups (summer, winter, and spring/fall).  Regional capacity factors vary from national averages.  The current reference case solar thermal annual capacity factor for California, for example, is assumed to average 40 percent; California’s current reference case PV capacity factor is assumed to average 24.6 percent. 
• Because solar technologies are more expensive than other utility grid-connected technologies, early penetration will be driven by broader economic decisions such as the desire to become familiar with a new technology or environmental considerations.  Minimal early years’ penetration is included by EIA as “floor” additions to new generating capacity (see “Supplemental and Floor Capacity Additions” below). 
• Solar resources are well in excess of conceivable demand for new capacity; therefore, energy supplies are considered unlimited  within regions (at specified daily, seasonal, and regional capacity factors). Therefore, solar resources are not estimated in NEMS.  In the seven regions where ST technology is not modeled, the level of direct, normal insolation (the kind needed for that technology) is insufficient to make that technology commercially viable through 2025. 
• NEMS represents the Energy Policy Act of 1992 (EPACT) permanent 10-percent investment tax credit for solar electric power generation by tax-paying entities. 

Wind-Electric Power Submodule 

Background 

Because of limits to windy land area, wind is considered a finite resource, so the submodule calculates maximum available capacity by Electricity Market Module Supply Regions.  The minimum economically viable wind speed is about 14 mph, and wind speeds are categorized into three wind classes according to annual average wind speed.  The RFM tracks wind capacity (megawatts) within a region and moves to the next best wind class when one category is exhausted.  For AEO2004, wind resource data on the amount and quality of wind per EMM region come from the National Renewable Energy Laboratory for 23 states¹¹¹ and a Pacific Northwest Laboratory study and  a subsequent update for the remainder.¹¹²  The technological performance, cost, and other wind data used in NEMS are derived by EIA from consultation with industry experts.¹¹³ Maximum wind capacity, capacity factors, and incentives are provided to the EMM for capacity planning and dispatch decisions. These form the basis on which the EMM decides how much power generation capacity is available from wind energy.  The fossil-fuel heat rate equivalents for wind are used for energy consumption calculation purposes only.   

Assumptions 

• Only grid-connected (utility and nonutility) generation is included.  The forecasts do not include off-grid or distributed electric generation. 
• In the wind submodule, wind supply is constrained by three modeling measures, addressing (1) average wind speed, (2) distance from existing transmission lines, and (3) resource degradation, transmission network upgrade costs, and market factors. 
• Available wind resource is reduced by excluding all windy lands not suited for the installation of wind turbines because of: excessive terrain slope (greater than 20 percent); reservation of land for non-intrusive uses (such as National Parks, wildlife refuges, and so forth); inherent incompatibility with existing land uses (such as urban areas, areas surrounding airports and water bodies, including offshore locations); insufficient continguous windy land to support a viable wind plant (less than 5 square kilometers of windy land in a 100 square kilometer area).  Half of the wind resource located on military reservations, U.S. Forest Service land, state forested land, and all non-ridge-crest forest areas are excluded from the available resource base to account for the uncertain ability to site projects at such locations.  These assumptions are detailed in the Draft Final Report to EIA on Incorporation of Existing Validated Wind Data into NEMS, November 2003. 
• Wind resources are mapped by distance from existing transmission capacity among three distance categories, within (1) 0-5, (2) 5-10, and (3) 10-20 miles on either side of the transmission lines. Additional transmission costs are added to the resources further from the transmission lines.  Transmission costs vary by region and distance from transmission lines, ranging from $8.80 per kW to $94 per kW (2002$). 
• Capital costs for wind technologies are assumed to increase in response to (1) declining natural resource quality,  such as terrain slope, terrain roughness, terrain accessibility, wind turbulence, wind variability, or other natural resource factors, (2) increasing cost of upgrading existing local and network distribution and transmission lines to accommodate growing quantities of intermittent wind power, and (3) market conditions, such as the increasing costs of alternative land uses, including  aesthetic or environmental reasons.  Capital costs are left unchanged for some initial share, then increased 20, 50, 100 percent, and finally 200 percent, to represent the aggregation of these factors.  Proportions of total wind resources in each category vary by EMM region. For all thirteen EMM regions, 1.2 percent of windy land is available with no cost increase, 1.8 percent is available with a 20 percent cost increase, 3.2 percent is available with a 50 percent cost increase, 3.2 percent is available with a 100 percent cost increase, and almost 91 percent of windy land is assumed to be available with a 200 percent cost increase. 
• Depending on the EMM region, the cost of competing fuels, and other factors, wind plants can be built to meet system capacity requirements or as a “fuel saver” to displace generation from existing  capacity. For wind to penetrate as a fuel saver, its total capital and fixed operations and maintenance costs minus applicable subsidies must be less than the variable operating costs, including fuel, of the existing (non-wind) capacity.  When competing in the new capacity market, wind is assigned a capacity credit that declines based on its estimated contribution to regional reliability requirements.  
• Because of downwind turbulence and other aerodynamic effects, the model assumes an average spacing between turbine rows of 5 rotor diameters and a lateral spacing between turbines of 10 rotor diameters. This spacing requirement determines the amount of power that can be generated from wind resources and is factored into requests for generating capacity by the EMM. 
• Capacity factors are assumed to increase to a national average of  43 percent in the best wind class resulting from taller towers, more reliable equipment, and advanced technologies.  Capacity factors for each wind class are calculated as a function of overall wind market growth. The capacity factors are assumed to be limited to about 45 percent for an average Class 6 site.  As better wind resources are depleted, capacity factors are assumed to go down. 
• AEO2004 does not allow plants constructed after 2003 to claim the Federal Production Tax Credit (PTC), a 1.8 cent per kilowatt-hour  tax incentive that expired on December 31, 2003.  Wind plants are assumed to depreciate capital expenses using the Modified Accelerated Cost Recovery Schedule with a 5-year tax life. 

Geothermal-Electric Power Submodule 

Background 

The Geothermal-Electric Submodule (GES), represents the generating capacity and output potential of 51 hydrothermal resource areas in the Western United States based on estimates provided in 1999 by DynCorp Corporation and subsequently modified by EIA.¹¹⁴ Hot dry rock resources are not considered cost effective until after 2025 and are therefore not modeled in the GES.  Both dual flash and binary cycle technologies are represented. The GES distributes the total capacity for each site within each EMM region among four increasing cost categories, with the lowest cost category assigned the base estimated costs, the next assigned higher (double) exploration costs, the third assigned a 33 percent increase in drilling and field costs, and the highest assigned both double exploration and 33 percent increased drilling and field costs.  Drilling and field costs vary from site to site but are roughly half the total capital cost (along with plant costs) of new geothermal plants; exploration costs are a relatively minor additional component of capital costs.   All quantity-cost groups in each region are assembled into increasing-cost supplies.  When a region needs new generating capacity, all remaining geothermal resources available in that region at or below an avoided cost level determined in the EMM are submitted (in three increasing cost subgroups) to compete with other technologies for selection as new generating supply.  Geothermal capital costs decline with learning.  For estimating costs for building new plants, new dual-flash capacity – the lower cost technology - is assigned an 80 percent capacity factor, whereas binary plants are assigned a 95 percent capacity factor; both are assigned an 87 percent capacity factor for actual generation. 

To realistically reflect capacity availability through 2025 at each of the 51 geothermal sites, each site's potential is limited to about 100 megawatts for each of four cost levels.  Second, annual maximum capacity builds are established for each site, reflecting industry practice of expanding development gradually.  For the reference case, each site is permitted a maximum development of 25 megawatts per year through 2015 and 50 megawatts per year thereafter; for the high renewables and DOE goals cases, the 50 megawatt annual limit applies to all years. 

Assumptions 

• Existing and identified planned capacity data are obtained directly by the EMM from Forms EIA-860A (utilities) and EIA-860B (nonutilities) and from supplemental additions (See Below). 
• The permanent investment tax credit of 10 percent available in all forecast years based on the EPACT applies to all geothermal capital costs. 
• Plants are not assumed to retire unless their retirement is reported to EIA.  Geysers units are not assumed to retire but instead are assigned the 35 percent capacity factors reported to EIA reflecting their reduced performance in recent years. 
• Capital and operating costs vary by site and year; values shown in Table 38 in the EMM chapter are indicative of those used by EMM for geothermal build and dispatch decisions. 

Biomass Electric Power Submodule 

Background 

Biomass consumed for electricity generation is modeled in two parts in NEMS.  Capacity in the wood products and paper industries, the so-called captive capacity, is included in the industrial sector module as cogeneration. Generation by the electricity sector is represented in the EMM, with capital and operating costs and capacity factors as shown in Table 38 in the EMM chapter, as well as fuel costs, being passed to the EMM where it competes with other sources.  Fuel costs are provided in sets of regional supply schedules.  Projections for ethanol are produced by the Petroleum Market Module (PMM), with the quantities of biomass consumed for ethanol decremented from, and prices obtained from, the EMM regional supply schedules. 

Assumptions 

• Existing and planned capacity data are obtained from Forms EIA-860A and EIA-860B. 
• The conversion technology represented, upon which the costs in Table 38 in the EMM chapter are based, is an advanced gasification-combined cycle plant that is similar to a coal-fired gasifier.  Costs in the reference case were developed by EIA to be consistent with coal gasifier costs.  Short-term cost adjustment factors are used. 
• Biomass cofiring can occur up to a maximum of 15 percent of fuel used in coal-fired generating plants.

Table 74.  U.S. Biomass Resources, by Region and Type, 2025 (Trillion Btu) Printer Friendly Version   Forest  Resources Urban Wood Waste/ Mill Residue   Energy  Crops  Agricultural Residue Total 1.  ECAR  363  156  183  407  1,110  2.  ERCOT  29  45  78  57  210  3.  MAAC  44  50  19  28  142  4.  MAIN  125  36  112  439  712  5.  MAPP  191  39  398  946  1,573  6.  NPCC/NY  40  63  59  3  165  7.  NPCC/NE  81  50  38  0  170  8.  SERC/FL  32  42  4  0  79  9.  SERC  342  307  217  61  927  10. SPP  225  138  387  264  1,014  11. NWP  414  180  0  53  647  12. W/RA  105  30  6  54  195  13. W/CNV  43  94  0  23  161    Total US  2,036  1,231  1,501  2,335  7,103

Fuel supply schedules are a composite of four fuel types: forestry materials, wood residues, agricultural residues and energy crops.  The first three are combined into a single supply schedule for each region which does not change over the forecast.  Energy crops data are presented in yearly schedules from 2010 to 2025 in combination with the other material types for each region. The forestry materials component is made up of logging residues, rough rotten salvable dead wood, and excess small pole trees.¹¹⁵ The wood residue component consists of primary mill residues, silvicultural trimmings, and urban wood such as pallets, construction waste, and demolition debris that are not otherwise used.¹¹⁶ Agricultural residues are wheat straw and corn stover only, which make up the great majority of crop residues.¹¹⁷  Energy crops data are for hybrid poplar, willow, and switchgrass grown on crop land, pasture land, or on Conservation Reserve lands.¹¹⁸  The maximum amount of resources in each supply category is shown in Table 74. 

Landfill-Gas-to-Electricity Submodule 

Background 

Landfill-gas-to-electricity capacity competes with other technologies using supply curves that are based on the amount of “high”, “low”, and “very low” methane producing landfills located in each EMM region.  An average cost-of-electricity for each type of landfill is calculated using gas collection system and electricity generator costs and characteristics developed by EPA’s “Energy Project Landfill Gas Utilization Software” (E-PLUS).¹¹⁹ 

Assumptions 

• Gross domestic product (GDP) and population are used as the drivers in an econometric equation that establishes the supply of landfill gas. 
• Recycling is assumed to account for 35 percent of the total waste stream by 2005 and 50 percent by 2010 (consistent with EPA’s recycling goals). 
• The waste stream is characterized into three categories: readily, moderately, and slowly decomposable material. 
• Emission parameters are the same as those used in calculating historical methane emissions in the EIA’s Emissions of Greenhouse Gases in the United States 2002.¹²⁰ 
• The ratio of “high”, “low”, and “very low” methane production sites to total methane production is calculated from data obtained for 156 operating landfills contained in the Government Advisory Associates METH2000 database.¹²¹ 
• Cost-of-electricity for each site was calculated by assuming each site to be a 100-acre by 50-foot deep landfill and by applying methane emission factors for “high”, “low”, and “very low” methane emitting wastes. 

Legislation 

Energy Policy Act of 1992 (EPACT) 

The RFM includes the investment tax and energy production credits established in the EPACT for the appropriate energy types.  EPACT provides a renewable electricity production tax credit (PTC) of 1.5 cents per kilowatt-hour for electricity produced by wind, applied to plants that become operational between January 1, 1994, and June 30, 1999; AEO2004 includes extension of the PTC (adjusted for inflation to 1.8 cents) through December 31, 2003, as provided in section 507 of the Tax Relief Extension Act of 1999 as well as by the Job Creation and Worker Assistance Act of 2002.  The credit extends for 10 years after the date of initial operation. EPACT also includes provisions that allow an investment tax credit of 10 percent for solar and geothermal technologies that generate electric power.  This credit is represented as a 10-percent reduction in the capital costs in the RFM. 

Alternative Renewable Technology Cases 

Three cases examine the effect on energy supply using alternative assumptions for cost and performance of non-hyrdo, non-landfill gas renewable energy technologies.  The Low Renewable case examines the effect if technology costs were to remain at current levels.  The High Renewable case examines the effect if technology energy costs were reduced by 2025 to 10 percent below Reference case values.  The DOE Goals case examines the effect of using cost and performance assumptions approximating published goals of the relevant program offices of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy (DOE/EE).

The Low Renewables case does not allow “learning-by-doing” effects to reduce the capital cost of biomass, geothermal, solar, or wind technologies beyond 2004 levels.  The construction of the first four units of biomass integrated gasification combined cycle units, utility-scale photovoltaic plants, or solar thermal plants are still assumed to reduce the technological optimism factor associated with those technologies.  All other parameters remain the same as in the Reference case. 

The High Renewables case assumes that the non-hydro, non-landfill gas renewable technologies are able to reduce their overall cost-of-energy produced in 2025 by 10 percent from the Reference case.  Because the cost of supply of renewable resources is assumed to increase with increasing utilization (that is, the renewable resource supply curves are upwardly sloping), the cost reduction is achieved by targeting the reduction on the “marginal” unit of supply for each technology in 2025 for the Reference case (that is, the next resource available to be utilized in the Reference case in 2025).  This has the effect of reducing costs for the entire supply (that is, shifting the supply curve downward by 10 percent).  As a result of the overall reduction in costs, more supply may be utilized, and a unit from higher on the supply curve may result in being the marginal unit of supply in the High Renewable case.  Thus the actual market-clearing cost-of-energy for a given renewable technology may not differ by much from the Reference case, although that resource is able to supply more energy than in the Reference case. These cost reductions are achieved gradually through “learning-by-doing”, and are only fully realized by 2025. 

For biomass, geothermal, and solar technologies, this cost reduction is achieved by a reduction in overnight capital costs sufficient to achieve the 10 percent targeted reduction in cost-of-energy.   As a result, the supply of biomass fuel is increased by 10 percent at every price level.  For geothermal, the capital cost of the lowest-cost site available in the year 2000 (Roosevelt Hot Springs) is reduced such that if it were available for construction in 2025, it would have a 10 percent lower cost-of-energy in the High Renewable case than the cost-of-energy it would have in 2025 were it available for construction in the Reference case.  For solar technologies (both photovoltaic and solar thermal power), the resource is assumed to be unlimited and the reductions in cost-of-energy are achieved strictly through capital cost reduction. 

Observation of wind energy markets indicates that improvements in performance (as measured by capacity factor) have, in recent years, dominated reductions in capital cost as a means of reducing cost-of-energy. Therefore, in the High Renewables case, wind capital costs are assumed to decline at the same rate relative to market growth as in the Reference case, but the rate of improvement in capacity factor is increased to meet the 10 percent targeted cost reduction.  Other assumptions within NEMS are unchanged from the Reference case. 

The DOE Goals case uses assumptions designed to correspond to those in the year 2020 Technologies Databook.¹²² These assumptions, summarized previously in Table 72 and Table 73, include: 

• Biomass:  In the DOE Goals case, capital costs are modified from reference case values such that they are similar to those in the Power Technologies Databook costs for biomass gasification by 2025.  To reflect greater optimism for biomass fuels, biomass supplies are increased 10 percent across all price steps for the four types of biomass. Fixed operations and maintenance costs are reduced about 14 percent to be consistent with Power Technologies Databook costs.  Biomass capacity factors are unchanged from the reference case. 

• Geothermal:  In the DOE Goals case, EIA assumes that (1) capital costs for all 51 sites in 2000 match higher EIA rather than Power Technologies Databook estimates for this “base” year,  (2) EIA assumptions for capital costs decline at a rate sufficient to match Power Technologies Databook estimates by 2010, meaning that DOE Goals case assumptions remain higher than DOE/EE assumed costs through 2009 and (3) the lowest cost geothermal site available in 2000 (Roosevelt Hot Springs), would, if available for selection in 2020 (decision year), meet the 2020 Power Technologies Databook capital cost goal in that year, about 36 percent below its current $1,900 per kilowatt ($2002) cost. Finally, because each of the 51 sites is separately priced, EIA applies the rate (rather than amounts) of capital cost decline necessary for Roosevelt Hot Springs to meet these requirements to all other 50 sites. Overall, each site’s capital cost declines by 3 percentage points per decision year from 2000-2010, and by 0.6 percentage point per year from 2011-2020, using the capital cost weights: 

Capital Cost Decline Weights Printer Friendly Version Decision Year  Weight  2000  1.00  2005  0.85  2010  0.70  2015  0.67  2020  0.64  2025  0.64

• Least cost geothermal sites  result from the interaction of (a) baseline cost estimates for each site, (b) cost adjustment factors, and (c) increased costs as least-cost units are taken and higher cost sites are chosen. Therefore, in the DOE Goals case results, actual 2020 marginal capital costs by 2020 will not necessarily be lower than in the reference case but will instead show greater quantities of geothermal available and chosen before attaining the higher marginal costs. 

• In the DOE Goals case, geothermal capacity factors and fixed operations and maintenance costs (O&M) are unchanged from the reference case. 

• Photovoltaics (Central Station):  EIA assumes reduced capital  and operations and maintenance costs, corresponding to utility scale flat plate “Thin Film” technology in the Power Technologies Databook. Performance is assumed unchanged from the reference case. 

• Solar Thermal: In the DOE Goals case, EIA assumes increased initial capital costs compared to the Reference case, with significantly improved performance (as measured by capacity factor); in addition, operations and maintenance costs are reduced.  This corresponds with the Central Receiver  (Solar Power Tower) technology in the Power Technologies Databook, which incorporates, at additional cost, increasing levels of thermal energy storage in the forecast years.  To reflect the improved dispatch characteristics of integrated thermal storage, the capacity credit for solar thermal technologies in this case is set equal to the regional capacity factor during the peak load period. 

• Wind:  EIA assumes reduced capital and operations and maintenance costs, with increased performance (as measured by capacity factor) in all wind classes.  The maximum allowable capacity factor for high-wind speed locations (Class 6) is set to 58 percent, and the growth rate parameters are increased to allow the model to achieve capacity factor goals specified in the EE Power Technologies Databook for 2020.  The Power Technologies Databook represents the capital cost of wind turbines for high-wind speed areas (Class 6) and low-wind speed areas (Class 4) improving at different rates.  To represent a single capital cost for all wind installations within NEMS, the average Power Technologies Databook capital cost for Class 6, Class 5 (the mean of the Class 4 and Class 6 values), and Class 4  was calculated, as weighted by the best available wind class in each region.  That is, if 4 of 13 regions had only Class 4 sites available, 7 regions had Class 5 sites available, and 2 regions had Class 6 sites available, Class 4 costs would be given a weight of 0.31, Class 5 costs a weight of 0.54, and Class 6 costs a weight of 0.15 in averaging the three costs.  Fixed operation and maintenance costs are set to correspond to levels indicated in the Power Technologies Databook. Because costs are assumed to decline (or increase, in the case of Solar Thermal) based on the exogenous cost trajectory of the Power Technologies  Databook, the normal learning function of the EMM does not apply to these capacity types.  Thus cost targets are achieved regardless of actual market penetration. 

Because costs are assumed to decline (or increase, in the case of Solar Thermal) based on the exogenous cost trajectory of the Power Technologies Databook, the normal learning function of the EMM does not apply to these capacity types.  Thus, cost targets are achieved regardless of actual market penetration. 

For both the High Renewables and DOE Goals cases, demand-side improvements are also assumed in the renewable energy technology portions of residential and commercial buildings, industrial processes, and refinery fuels modules.  Details on these assumptions can be found in the corresponding sections of this report. 

Supplemental and Floor Capacity Additions 

Table 75. Post-2001 Supplemental Capacity Additions (Megawatts, Net Summer Capability) Printer Friendly Version Rationale  Biomass  Conven tional Hydro- electric  Geothermal  Landfill Gas  Solar  Thermal  Solar  Photovoltaic  Wind  Total  Mandates1  47.5 0.0  0.0 9.0  0.0 0.0 921.7 969.2 RenewablePortfolio     Standards  254.2 0.0  675.5 148.2 107.6 6.4 748.9 1940.8 California AB18902  0.0 21.0  0.0  19.5 0.0       0.0 181.6 222.1 Other Reported Plans3  42.1 0.0  58.8  87.4 0.0 1.0 1040.1 1229.4 Total  343.8 21.0  734.3 255.1 107.6 7.4 2892.3 4361.5

In addition to capacity projected through the use of the EMM and RFM, including 6.7 gigawatts additional renewables in the electric power sector, 4.3 gigawatts added in the large end-use heat and power sector, and another 900 megawatts in the small end-use sector, AEO2004 also includes 4,362 megawatts additional renewables generating capacity identified by EIA as entering service through 2025 (Supplemental Additions). Summarized in Table 75 and detailed in Table 76, some of the capacity represents mandated new capacity required by state laws, EIA estimates for expected new capacity under state-enacted renewable portfolio standards (RPS), estimates of winning bids in California’s renewables funding program (Assembly Bill 1890), expected new capacity under known voluntary programs, such as “green marketing” efforts, and other publicly stated plans. The additions do not include off-grid or distributed photovoltaics or hydroelectric power. 

For AEO2004, expectations for planned new capacity from state RPS are significantly reduced from expectations in AEO2003 in recognition of some states’ ongoing successful reliance on existing capacity or other measures (including exemptions) rather than on new additions.  However, AEO2004 also includes expectations of significantly more planned non-mandated new wind capacity than in AEO2003, ostensibly reflecting wind power’s becoming increasingly competitive (albeit with incentives) and possible wind industry interest in marketing renewable energy credits in RPS, “green power,” and other markets 

In addition to the Supplemental Additions, projections also include 75.5 megawatts of central station thermal-electric and 332.5 megawatts central station photovoltaic (PV) generating capacity (“Floors”) assumed by EIA to be installed for reasons in addition to least-cost electricity supply. 

Notes and Sources

Released: February 2004