Report#:DOE/EIA-0554(2000)
January 21, 2000 
(Next Release: 
January, 2001)

[Errata as of 4/4/2000]

Introduction

The NEMS Renewable Fuels Module (RFM) consists of five distinct submodules that represent the major renewable energy technologies.  Although it is described here, conventional hydroelectric is  included in the Electricity Market Module (EMM) and is not part of the RFM.  Similarly, ethanol modeling is  included in the Petroleum Market Module (PMM).  Some renewables, such as 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 require 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 wind, solar, and geothermal 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 only with modules outside of the RFM and not with other RFM submodules.  These interactions occur through common elements of the model 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.  

For AEO2000, two increasing costs are superimposed onto the capital costs of renewable energy technologies 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 reflecting 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, municipal solid waste, solar, and wind technologies.

• For biomass and wind only, increased costs are assumed to result from a large cumulative increase in use of one of these resources, reflecting any or all of three general 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 AEO2000, 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 wind, the increases are 0, 20, 50, 100 and 200 percent respectively.  The size of the resource increments vary by technology and region.

For an in-depth discussion of the learning functions, see the EMM section and the background section of the model summary for the Geothermal Electric Submodule. A detailed description of the RFM is provided in the EIA publication, Renewable Fuels Module of the National Energy Modeling System, Model Documentation 2000, DOE/EIA-M069(2000), January 2000.

Key Assumptions

Nonelectric Renewable Energy Uses

In addition to projections for renewable energy used in electricity generation, the AEO2000 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. Additional renewable energy applications, 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 specifically and EMM in general consider only grid-connected central station electricity generation.  Off-grid and distributed sources, such as off-grid and distributed grid-connected applications of photovoltaic, dish-Stirling solar, and wind generation, are not included in the energy projections for the AEO2000.  The renewable submodules that interact with the EMM are the central station grid-connected solar (thermal and photovoltaic), wind, geothermal, biomass, and MSW 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 data are central to the build and dispatch decisions of the EMM with the exception of MSW.  The values are presented in Table 37 of the EMM section.

                                                        Conventional Hydroelectricity

Background

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.  

Assumption

• 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).

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 fixed-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 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 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).  The current solar thermal  annual capacity factor for the region including California, for example, is assumed to average 40 percent; California’s current PVcapacity 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 year’s 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).  Accordingly, there is no reason to track solar resources 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 models the Energy Policy Act of 1992 (EPACT) 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.¹¹¹   The technological performance, cost, and other wind data used in NEMS are derived  by EIA from consultation with industry experts.¹¹²  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 provided to the report writer 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.

• First 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.

• For AEO2000, 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.

Geothermal-Electric Power Submodule

Background

In developing geothermal capacity growth projections, the focus is on hydrothermal resources;  extraction of energy from hot dry rock resources is not included.  This is because the technology probably will at best be available after 2010, and reliable cost and resource data are not available.  The Geothermal-Electric Power Submodule (GES) utilizes a process of resource accounting based on Sandia National Laboratory’s 1991 geothermal resource assessment.¹¹³  Site-specific costs, including those for drilling, steam collection, and electricity transmission to the grid, as well as site characteristics, are used in identifying available resources and capacities by EMM region.  The cost and performance values are based on dual flash and binary cycle technologies.  The costs from 51 sites are aggregated into a set of regional supply curves for each year.  For each iteration of a model run, a value for avoided cost is obtained from the Electricity Capacity Planning Submodule to establish the levelized cost at which to truncate the curves, thereby excluding the higher cost resources.  Capital cost learning on the generating units which emulates what is done in the EMM is incorporated in the GES.¹¹⁴ For AEO2000, the capacity factor has been set at 87 percent, based on historical data.

Assumptions

• Existing and planned capacity data are accessed directly by the EMM.  The data are obtained from Forms EIA-860 and EIA-867.

• An investment tax credit of 10 percent is assumed to be available in all forecast years based on the EPACT.

• Plant retirements are generally assumed to occur 30 years after startup.  An exception is made for wells affected by a project to bring water to parts of The Geysers site which is expected to halt the enthalpy decline occurring there. Of these (six) wells, half are assumed to be retired after 35 years, the others in 40 years.

• Capital and operating costs vary by site and year; values shown in Table 37 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 37, 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 accessed directly by the EMM.  The data are obtained from Forms EIA-860 and EIA-867.

• The conversion technology represented, upon which the costs in Table 37 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.  However, co-firing is not enumerated as biomass capacity but remains accounted as part of coal-fired capacity.

In place of the previously used capacity constraints, short-term and long-term cost adjustment factors have been installed.  These values are described in the RFM introduction.

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.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 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.¹¹⁸  The maximum amount of resources in each supply category is shown in Table 70.

Table 70.  U.S. Biomass Resources, by Region and Type, 2020

Municipal Solid Waste-Electric Power Submodule

Background

Municipal solid waste (MSW) combustion is treated within NEMS as a separate technology whose electricity production is determined exogenous to the EMM.  The cost of producing electricity is passed to the EMM only as an input to the calculation that derives the average cost of producing electricity.  Energy from MSW is a byproduct of waste disposal activity and, therefore, does not compete against other technologies in model decisions regarding new capacity additions.¹¹⁹

Assumptions

• MSW is assumed to displace other energy forms lower in the merit order.

• Build decisions are based on a stepwise process involving waste disposal parameters.

• Gross domestic product (GDP) and population are used as the drivers in an econometric equation that establishes the supply of MSW.

• The values disposal parameters are extrapolated from historical Environmental Protection Agency (EPA) values for MSW and multiplied by 1.47 to reflect a broader definition of materials known to be combusted.  The factor 1.47 is derived from information in the Biocycle State Survey.¹²⁰

• The heat content of the MSW is set at 5,190 Btu per pound, and is assumed to remain at that level throughout the projection.

• The percentage of waste combusted is assumed to remain constant at 11 percent of a growing waste stream.  Using the larger Biocycle-based value for generation of the MSW waste stream, the EIA estimated percentage currently combusted equals 12 percent of the alternative EPA estimate of waste.¹²¹

• The total energy from MSW projected for the United States is limited to the portion currently used for electricity generation (about 92 percent) and is disaggregated into regions.  This regional breakdown is performed by maintaining the projected 1996 distribution of these factors as represented in the EIA database of MSW plants.  Steam from MSW is represented in industrial cogeneration.

• An estimate is made of energy produced from landfill gas.  Data values are entered in a spreadsheet that considers existing and additional landfills and a profile of gas generation from the waste. It is assumed that the percent of the gas emitted that will be captured for energy conversion will increase from 13 percent in 1995 to 40 percent in 2020, based on an EPA estimate of a tripling of landfills that will capture the gas. The resulting generating capacity is added to the capacity for MSW combustion, is disaggregated by region and passed to the EMM.

Legislation

Energy Policy Act of 1992 (EPACT)

The RFM includes the investment tax and energy production credits called for in the EPACT for the appropriate energy types. EPACT provides a renewable electricity production credit of 1.5 cents per kilowatt-hour for electricity produced by wind, applied to plants that become operational between January 1, 1994, and December 31, 1999;  AEO2000 does not assume that the EPACT credit will be extended.  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-860 and EIA-867 and capacity projected through the use of the EMM/RFM, the AEO2000 also includes 2,897 megawatts additional generating capacity powered by renewable resources. Summarized in Table 71 and detailed in Table 72, 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), expected new capacity under known voluntary programs, such as “green marketing” efforts, and other reported plans.

Table 71.  Post-1999 Supplemental Capacity Additions

Table 72.  Planned Post-1999 U.S. Generating Capacity Using Renewable Resources

Climate Change Action Plan

Action Item 26, “Form Renewable Energy Market Mobilization Collaborative with Technology Demonstration,” of the Climate Change Action Plan (CCAP),¹²² is designed to spur field validation of selected renewable energy technologies by supporting specified electric utility tests.  The demonstrations, along with information dissemination, intend to address market barriers by increasing utility and investor confidence in the technologies.  Technologies identified in Action Item 26 include assistance to “ice breaker” geothermal plants, site testing advanced wind turbines, and assistance and collaboration in launching test biomass-fueled and photovoltaic electricity generating technologies.

The electricity generating capacity effects on AEO2000 of Action Item 26 are incorporated in EIA’s projections for renewable technologies.  The supplemental capacity additions include additions that will be cost-shared by DOE and industry. While the stated goal of this action item is “increased utility and investor experience and confidence” in renewable technologies, in general, no additional cost declines beyond those discussed above are assumed.