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 seven submodules representing various renewable energy sources,
biomass, geothermal, conventional hydroelectricity, landfill gas, solar
thermal, solar photovoltaics, and wind108.
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 water, 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 one of the first electric generation
technologies, 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 the availability
of low-cost energy storage systems.
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 AEO2006 contains projections of nonelectric
renewable energy uses for industrial and residential wood consumption,
solar residential and commercial hot water heating, biofuels 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
The RFM considers only grid-connected central station electricity generation
systems. The RFM submodules that interact with the EMM are the central
station grid-connected biomass, geothermal, conventional hydroelectricity,
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.
Capital Costs
Capital costs for renewable technologies are affected by several factors.
Capital costs for technology to exploit some resources, especially geothermal,
hydroelectric, and wind power resources, are assumed to be dependent on
the quality, accessibility, and/or other site-specific factors in the areas
with exploitable resources. These factors can include additional costs
associated with reduced resource quality; need to build or upgrade transmission
capacity from remote resource areas to load centers; or local impediments
to permitting, equipment transport, and construction in good resource areas
due to siting issues, inadequate infrastructure, or rough terrain.
Short-term cost adjustment factors 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
factors, which are applied to all new electric generation capacity, are
a function of past production rates and are further described in The Electricity
Market Module of the National Energy Modeling System: Model Documentation
Report, available at http://www.eia.gov/bookshelf/docs.html.
Independent of the other two factors, capital costs for all electric generation
technologies, including renewable technologies, are assumed to decline
as a function of growth in installed capacity for each technology.
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 2005, DOE/EIA-M069(2005)
(Washington, DC, 2005).
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 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 Energys Office of Energy Efficiency and Renewable Energy and the Electric
Power Research Institute (EPRI).109 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; Californias 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;
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 2030.
- NEMS represents the Energy Policy Act of 1992 (EPACT92) 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 average wind speed
is about 14 mph, and wind speeds are categorized by annual average wind
speed based on a classification system from the Pacific Northwest Laboratory.
The RFM tracks wind capacity (megawatts) by resource quality, distance
to transmission, and other resource costs within a region and moves to
the next best wind resource when one category is exhausted. For AEO2006,
wind resource data on the amount and quality of wind per EMM region come
from the National Renewable Energy Laboratory for 23 states110 and a Pacific
Northwest Laboratory study and a subsequent update for the remainder.111 The technological performance, cost, and other wind data used in NEMS
are derived by EIA from available data and in 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 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 costs are affected 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 $4.10 per kW to $12.30 per kW (2002$).
- 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 combined,
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, about 6.5 megawatts per square kilometer of windy land, and
is factored into requests for generating capacity by the EMM.
- Capacity factors are assumed to increase to a national average of 44 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 48 percent for an average Class 6 site. As better
wind resources are depleted, capacity factors are assumed to go down.
- AEO2006 does not allow plants constructed after 2007 to claim the Federal
Production Tax Credit (PTC), a 1.9 cent per kilowatt-hour tax incentive
that is set to expire on December 31, 2007. 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.113 Hot dry rock resources are not considered cost effective
until after 2030 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 of new geothermal plants; exploration costs are a relatively
minor component of capital costs. All quantity-cost groups in each region
are assembled into increasing-cost suppy arrays. 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 2030 at each of
the 51 geothermal sites, each site's potential is limited to about 100
megawatts for each of the 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.
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, except
through 2007 when the 1.9 cent production tax credit is available to this
technology and is assumed chosen instead.
- 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 Form EIA-860.
- 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.
Fuel supply schedules are a composite of four fuel types: forestry materials,
wood residues, agricultural residues and energy crops. Energy crop data
are presented in yearly schedules from 2010 to 2030 in combination with
the other material types for each region. The forestry materials component
is made up of logging residues, rough rotten salvageable dead wood, and
excess small pole trees.114 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.115 Agricultural residues are wheat straw, corn stover, and a number of other
major agricultural crops.116 Energy crop data are for hybrid poplar, willow,
and switchgrass grown on crop land, pasture land, or on Conservation Reserve
Program lands.117 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
EPAs Energy Project Landfill Gas Utilization Software (E-PLUS).118
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 EPAs 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 EIAs Emissions of Greenhouse Gases in the United
States 2003.119
- 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.120
- 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.
Conventional Hydroelectricity
The conventional hydroelectricity submodule represents U.S. potential for
new conventional hydroelectric capacity 1 megawatt or greater from new
dams, existing dams without hydroelectricity, and from adding capacity
at existing hydroelectric dams. Summary hydroelectric potential is derived
from reported lists of potential new sites assembled from Federal Energy
Regulatory Commission (FERC) license applications and other survey information,
plus estimates of capital and other costs prepared by the Idaho National
Engineering and Environmental Laboratory (INEEL).121 Annual performance
estimates (capacity factors) were taken from the generally lower but site
specific FERC estimates rather than from the general estimates prepared
by INEEL, and only sites with estimated costs 10 cents per kilowatthour
or lower are included in the supply. Pumped storage hydro, considered a
nonrenewable storage medium for fossil and nuclear power, is not included
in the supply; moreover, the supply does not consider offshore or in-stream
(non-impoundment) hydro, efficiency or operational improvements without
capital additions, or additional potential from refurbishing existing hydroelectric
capacity.
In the hydroelectricity submodule, sites are first arrayed by NEMS region
from least to highest cost per kilowatthour. For any years capacity decisions,
only those hydroelectric sites whose estimated levelized costs per kilowatthour
are equal to or less than an EMM determined avoided cost (the least cost
of other technology choices determined in the previous decision cycle)
are submitted. Next, the array of below-avoided cost sites is parceled
into three increasing cost groups, with each group characterized by the
average capacity-weighted cost and performance of its component sites.
Finally, the EMM receives from the conventional hydroelectricity submodule
the three increasing-cost quantities of potential capacity for each region,
providing the number of megawatts potential along with their capacity-weighted
average overnight capital cost, operations and maintenance cost, and average
capacity factor. After choosing from the supply, the EMM informs the hydroelectricity
submodule, which decrements available regional potential in preparation
for the next capacity decision cycle.
Legislation
Energy Policy Act of 1992 (EPACT92) and 2005 (EPACT05)
The RFM includes the investment and energy production tax credits codified
in the Energy Policy Act of 1992 (EPACT 92) as amended most recently by
the Energy Policy Act of 2005 (EPACT 05). The investment tax credit established
by EPACT 92 provides a credit to Federal income tax liability worth 10
percent of initial investment cost for a solar, geothermal, or qualifying
biomass facility. This credit was temporarily raised to 30 percent for
some solar projects and extended to residential projects. This change
is reflected in the commercial and residential modules, but is not reflected
for utility-scale installations, where impacts are expected to be minimal.
The production tax credit, as established by EPACT 92, applied to wind
and certain biomass facilities. As amended, most recently by EPACT 05,
it provides a 1.9 cent tax credit for every kilowatt-hour of electricity
produced for the first 10 years of operation for a facility constructed
by December 31, 2007. The value of the credit, originally 1.5 cents, is
adjusted annually for inflation. With the EPACT 05 amendments, the production
tax credit is available for electricity produced from qualifying geothermal,
animal waste, certain small-scale hydroelectric, landfill gas, municipal
solid waste, and additional biomass resources. Poultry litter and geothermal
resources receive a 1.9 cent tax credit for the first 10 years of facility
operations. All other renewable resources receive a 0.9 cent tax credit
for the first 10 years of facility operations. The investment and production
tax credits are exclusive of one another, and may not both be claimed for
the same facility.
Alternative Renewable Technology Cases
Two cases examine the effect on energy supply using alternative assumptions
for cost and performance of non-hyrdo, non-landfill gas renewable energy
technologies. The 2006 Renewable Technology 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 2030
to 10 percent below Reference case values.
The 2006 Renewables case does not allow learning-by-doing effects to
reduce the capital cost of biomass, geothermal, solar, or wind technologies
or to improve wind capacity factor beyond 2006 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
2030 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 2030 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 contributes more energy supply than in the
Reference case. These cost reductions are achieved gradually through learning-by-doing,
and are only fully realized by 2030.
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 2005 (Roosevelt Hot Springs) is reduced such that if it were available
for construction in 2030, it would have a 10 percent lower cost-of-energy
in the High Renewable case than the cost-of-energy it would have in 2030
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, the reduction in wind levelized cost comes from both
modestly reduced capital cost and improved capacity factor. Other assumptions
within NEMS are unchanged from the Reference case.
For the High Renewables case, 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
Of the nearly 22 gigawatts of new renewable energy capacity projected to
enter service in the electric power sector after 2004, 11.7 gigawatts of
central station supplemental additions were specifically added by EIA
to account for identified new renewable energy projects and for limited
amounts of new capacity determined to be highly likely to be built under
state requirements such as renewable portfolio standards (RPS) and mandates
or under voluntary goals, green power marketing programs, and other commercial
ventures (summarized in Table 75 and detailed in Table 76).
Further, in addition to the supplemental capacity additions in the electric
power sector, for AE02006 projections for new end-user-sited capacity include
748 megawatts of new photovoltaics (PV) capacity representing specifically
identified expected new grid-connected end-user PV capacity or representative
volumes known or assumed by EIA to be expected over the forecast period
or emanating from state RPS and other requirements.
Renewable Fuels Module Tables
Coal Market Notes |