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).112

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, landfill gas (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. 

Key Assumptions

Nonelectric Renewable Energy Uses

In addition to projections for renewable energy used in central station electricity generation, the AEO2001 contains projections of nonelectric renewable energy uses for industrial and residential wood consumption, solar residential and commercial hot water heating, and residential and commercial geothermal (ground-source) heat pumps. Assumptions for their projections are found in the residential, commercial, and industrial 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

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. Most provide specific data that characterize that resource in a useful manner.  In addition, a set of technology cost and performance values is provided directly to the EMM.  These values are central to the build and dispatch decisions of the EMM. The values are presented in Table 43.  Overnight capital costs and other extended performance characteristics are presented in Table 77.

Table 77. Cost and Performance Characteristics for Renewable Energy Generating Technologies: Two Cases

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 rapid U.S. buildup in a single year and reflect limitations on the infrastructure (for example, manufacturing, resource assessment, construction expertise) to accommodate unexpected demand growth.  These short-term factors are invoked when demand for new capacity in any year exceeds 30 percent of the prior year’s total U.S. capacity.  For every 1 percent increase in total U.S. capacity over the previous year greater than 30 percent, capital costs rise 0.5 percent.  These factors apply to biomass, geothermal, solar, and wind technologies.

• For biomass, geothermal and wind, higher costs are assumed to result from a large cumulative increase in use of one of these resources, reflecting any or all of three general longer-term cost adjustment factors: (1)  resource degradation, (2) transmission network upgrades, and (3 ) market factors.  Presumably best land resources are used first.  Increasing resource use necessitates resort to less efficient land - 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, for AEO2001, each EMM region’s biomass and wind resource estimates are parceled into five cost levels.  For biomass, the percentage cost increases that are applied to initial capital costs are 0, 15, 50, 75 and 100 percent for successive increments of the resource.  For geothermal, four successive increments incur 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.  For wind, the increases are 0, 20, 50, 100 and 200 percent respectively.  The size of the resource increments vary 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 Electricity Market Module section 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 2001, DOE/EIA-M069(2001), January 2001.

Solar Electric Submodule

Background

The Solar Electric Submodule (SOLES) currently includes 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 primarily 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).113 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 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.

• In order to incorporate assumed improvements in photovoltaic technologies, all PV capacity factors are assumed to improve linearly a total of 10 percent from 2005 through 2015; for example, California’s annual average capacity factor for PV increases from 24.6 percent to almost 27.1 percent by 2015.

• 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.  Early years’ penetration for such reasons is included as supplemental additions.

• 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 2020.

• 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 13 mph, and wind speeds are categorized into three wind classes according to annual average wind speed.  The RFM keeps track of wind capacity (megawatts) within a region and moves to the next best wind class when one category is exhausted.  Wind resource data on the amount and quality of wind per EMM region come from a Pacific Northwest Laboratory study and a subsequent update.114   The technological performance, cost, and other wind data used in NEMS are derived  by EIA from consultation with industry experts.115  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.

• Availability of wind power (among three wind classes) is based on the Pacific Northwest Laboratory Environmental and Moderate Land-Use Exclusions Scenario, in which some of the windy land area is not available for siting of wind turbines. The percent of total windy land unavailable under this scenario consists of all environmentally protected lands (such as parks and wilderness areas), all urban lands, all wetlands, 50 percent of forest lands, 30 percent of agricultural lands, and 10 percent of range and barren lands.

• Wind resources are mapped by distance from existing transmission capacity among three distance categories, accepting wind resources within (1) 0-5, (2) 5-10, and (3) 10-20 miles on either side of the transmission lines. Transmission cost factors are added to the resources further from the transmission lines.

• Capital costs for wind technologies are also 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, the increasing costs of alternative land uses, including for 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 in each category vary by EMM region.

• 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 “fuel savers” 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 from the EPACT,  must be less than the variable operating and fuel costs for existing (non-wind) capacity.

• 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 windy land area and is factored into requests for generating capacity by the EMM.

• It is expected that wind turbine technology will improve in performance and that blade lengths will increase, as the cubic relationship between the area swept by the rotor and power generation provides a large incentive for increasing blade length.  Capacity factors are assumed to increase to a national average of about 34 percent in the best wind class. However, as better wind resources are depleted, capacity factors are assumed to go down.

• AEO2001 includes the 1.5 (adjusted for inflation to 1.7) cent per kilowatthour Federal production tax credit (PTC) received for the first 10 years of a new wind unit’s production; the PTC is applied to all wind units entering service from 1993 through 2001. (All wind units are assumed owned by taxpaying entities).

Geothermal-Electric Power Submodule

Background

The Geothermal-Electric Submodule (GES), simplified for AEO2001, represents the generating capacity and output potential of 51 hydrothermal resource areas in the Western United States based on updated estimates provided in 1999 by DynCorp Corporation and subsequently adapted by EIA.116 Hot dry rock resources are not considered cost effective until after 2020 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 (the high estimate) within each EMM region among four increasing cost categories, with the lowest cost category (the low estimate of available capacity) 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 as for other technologies.  For estimating costs for building new plants, AEO2001 new dual-flash capacity – the lower cost technology - is assigned an 95 percent capacity factor, whereas binary plants are assigned a 95 percent capacity factor; both are assigned an 87 percent capacity factor for actual generation

Assumptions

• Existing and planned capacity data are obtained directly by the EMM from Forms EIA-860A (utilities) and EIA-860B (nonutilities).

• 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 have the 35 percent capacity factors reported to EIA reflecting declining performance in recent years.

• Capital and operating costs vary by site and year; values shown in Table 43 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 43, 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, these same 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 43 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.

• Biomass cofiring can occur up to a maximum of 5 percent of fuel used in coal-fired generating plants.  Short-term and long-term cost adjustment factors are used.

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 for the full forecast period.  Energy crops data are presented in yearly schedules from 2010 to 2020 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.117 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.118  Agricultural residues are wheat straw and corn stover only, which make up the great majority of crop residues.119  Energy crops data is for hybrid poplar, willow and switchgrass grown on crop land, pasture land, or on Conservation Reserve lands. Energy crop costs range from zero to over five dollars per million Btu.120  The maximum amount of resources in each supply category is shown in Table 78.

Table 78.  U.S. Biomass Resources, by Region and Type, 2020

Landfill-gas-to-Electricity Submodule

Background

Beginning with AEO2001, a new submodule has been added to NEMS, to let landfill-gas-to-electricity technologies compete economically with other generation technologies.  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 electricity market module 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)121.

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 recyclying 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 1998122.

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 database123.

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; AEO2001 includes extension of the PTC (adjusted for inflation to 1.7 cents) through December 31, 2001 as provided in section 507 of the Tax Relief Extension Act of 1999.  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.

Supplemental Capacity Additions

In addition to the reported generating capacity plans from the EIA-860A and EIA-860B and capacity projected through the use of the EMM/RFM, the AEO2001 also includes 5,356 megawatts additional generating capacity powered by renewable resources. Summarized in Table 79 and detailed in Table 80, some of the capacity represents mandated new capacity required by state laws, EIA estimates for expected new capacity under recent state-enacted renewable portfolio standards (RPS), estimates of winning bids in California’s renewables funding program (Assembly Bill 1890  but not its August, 2000, extension), expected new capacity under known voluntary programs, such as “green marketing” efforts, and other publicly stated plans.

Table 79.  Post-1999 Supplemental Capacity Additions

Table 80. Planned Post-1999 U.S. Generating Capacity Using Renewable Resources

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