United States
Environmental Protection
Agency
Air and
Radiation
(ANR-445)
EPA/400/R -92/005
March 1992
Renewable Electric Generation
An Assessment of Air Pollution
Prevention Potential
ICF Incorporated for --
Global Change Division
Office of Air and Radiation
U.S. Environmental Protection Agency
Printed on Recycled Paper
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RENEWABLE ELECTRIC GENERATION
An Assessment of
Air Pollution Prevention Potential
Final Report
By
Marc Chupka
David Howarth
ICF Incorporated
Cathy Zoi
Project Officer and Editor
Global Change Division
Office of Air and Radiation
United States Environmental Protection Agency
March 1992
-------
Acknowledgements
The authors would like to thank Caleb Kleppner, Robin Langdon,
and Dara O'Rourke of ICF Incorporated and David DeBusk and
Brendan MacMillan of The Bruce Company for their contributions.
We would also like to thank the many individuals who reviewed
and provided useful comments on earlier versions of this report.
-------
CONTENTS
EXECUTIVE SUMMARY ES 1
CHAPTER I: ELECTRICITY GENERATION, ENVIRONMENTAL IMPACT,
AND REGULATION
ELECTRICITY AS AN ENERGY SOURCE
Sources of Supply
Growth in Demand
-1
-2
-2
-5
-5
-6
-6
-6
-9
-9
-9
-9
Methane 1-11
ELECTRICITY AS A POLLUTION SOURCE
Environmental Impacts
Air Emissions and Environmental Controls
Sulfur Dioxide
Nitrogen Oxides
Paniculate Matter
Carbon Monoxide
Volatile Organic Compounds
Carbon Dioxide
ELECTRICITY SUPPLY AND REGULATION
Rate Regulation and Traditional Supply Decisions
Demand-Side Options
Emerging Competition and Supply Choices
Qualifying Facilities under PURPA
Independent Power Producers
Competitive Procurement and Bidding ..
Current and Planned Capacity
REGULATION AND POLLUTION PREVENTION IN ELECTRICITY GENERATION
The Pollution Prevention Approach
Pollution Prevention, External Costs, and Renewable Energy
REGULATORY REFORM AND RENEWABLE ELECTRIC OPPORTUNITIES
Integrated Resource Planning and Pollution Prevention
Direct Environmental Valuation
Other Valuation Options
Allocation of Future Regulatory and Cost Risk
Fuel Price Risk .
Regulatory Risk
Technology Risk
The Clean Air Act Amendments of 1990
-11
- 13
- 14
- 14
- 15
- 15
- 15
- 17
- 17
-19
-20
-22
-27
-27
-31
-31
-32
-32
-34
-35
CHAPTER II: RENEWABLE ELECTRIC OPPORTUNITIES
THE RENEWABLE ENERGY RESOURCE BASE 11-1
lit
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IMPROVEMENTS IN CONVERSION TECHNOLOGIES 11-4
Recent Market Experience 11-4
Renewable Technology Research and Development 11-6
Expanding International Markets for Renewable Technologies 11-6
FAVORABLE POLITICAL CLIMATE FOR RENEWABLES 11-8
Public Environmental Concern II -10
Oil Dependence 11-10
Greenhouse Gas Protocols II -11
POLICIES TO INCREASE RENEWABLE ENERGY CONTRIBUTIONS II - 11
Greater Environmental Valuation in Resource Planning II -11
Environmental Taxes and Penalties 11-13
Regulation and Planning for Intermittent Generation 11-13
Additional Research, Development and Demonstration Support 11-14
Cumulative Commercial Experience and Learning Curves 11-15
Tax Policies to Promote Investments in Renewables 11-17
Energy Pncing and the "Level Playing Field' 11-17
CHAPTER III: THE EPA MARKET ASSESSMENT
CONSTRUCTION OF THE EPA RENEWABLE TECHNOLOGY PENETRATION SCENARIOS 111-1
DOE/SERI Scenarios III-3
EPA Scenarios III-4
Base Case III-4
Enhanced Market Scenario III-4
EPA MODEL DESCRIPTION III-5
INTERPRETATION OF MODEL RESULTS III-7
Avoided Costs III-7
Emissions III-8
AIR POLLUTION PREVENTION ESTIMATES 111-10
Base Case Generation and Air Pollution Prevented 111-10
Enhanced Market Generation and Air Pollution Prevented 111-14
RENEWABLE AND FOSSIL GENERATION COSTS 111-18
Base Case Generation Costs 111-18
Enhanced Market Generation Costs III-20
'Backstop1 Technology Costs 111-20
ENVIRONMENTAL COSTS 111-21
Air Pollution Prevention Costs 111-21
Externalities Penalty Cases III-24
CHAPTER IV: BIOMASS ELECTRIC GENERATION
BIOMASS RESOURCE BASE IV - 3
TOTAL U.S. RESOURCE BASE IV - 3
GEOGRAPHIC DISTRIBUTION IV - 7
IV
-------
WOOD, WOOD WASTE, AND AGRICULTURAL WASTE IV - 7
CONVERSION TO ELECTRICITY IV - 7
Existing Technologies IV -12
Current Economics IV -14
EMERGING TECHNOLOGIES IV - 14
Emerging Conversion Technologies IV -14
Whole Tree Energy IV -14
Biomass Gasification and Combustion IV -15
Costs IV -17
Emerging Biomass Production Technologies IV -19
Increased Recovery of Biomass Wastes IV -19
Short-Rotation Woody Crop (SRWC) Feedstocks IV - 20
MARKET ASSESSMENT IV - 22
Costs IV - 24
Air Pollution Prevented IV - 27
MUNICIPAL SOLID WASTE IV - 27
CONVERSION TO ELECTRICITY IV - 27
Existing Technologies IV - 27
Current Economics IV - 28
EMERGING CONVERSION TECHNOLOGIES IV - 28
MARKET ASSESSMENT IV - 29
Costs IV - 29
Air Pollution Prevented IV - 30
LANDFILL AND DIGESTER GAS IV - 33
CONVERSION TO ELECTRICITY IV - 33
Gas Production/Collection IV - 33
Conversion Technologies IV - 35
Current Economics IV - 35
EMERGING TECHNOLOGIES IV - 36
Gas Production IV - 36
Conversion Technologies IV - 36
Costs IV - 38
MARKET ASSESSMENT IV - 38
Costs IV - 40
Air Pollution Prevented IV - 43
CHAPTER V: GEOTHERMAL ELECTRICITY GENERATION
RESOURCE BASE V - 1
Resource Base, Accessible and Reserves V - 1
Geographic Distribution V - 3
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CONVERSION TO ELECTRICITY V - 5
Existing Technologies V - 5
Resources Recovered V - 9
Current Economics V - 9
EMERGING CONVERSION TECHNOLOGIES V - 12
Efficiency/Performance V -12
Potential Technology and Multiple Pathways V-12
Hydrothermal Resources V -14
Geopressured Brines V -15
Hot Dry Rock V - 15
Magma V -16
MARKET ASSESSMENT V - 16
Costs V - 17
Air Pollution Prevented V - 20
CHAPTER VI: CONVENTIONAL HYDROPOWER
RESOURCE BASE VI - 1
CONVERSION TO ELECTRICITY VI - 3
Types of Hydroelectric Projects VI - 3
Storage Projects VI - 3
Run-of-River Project VI - 3
Diversion Projects VI - 7
Head VI - 7
Turbine Type VI - 7
Operating Modes VI - 8
Environmental Impacts VI - 8
Resources Recovered and Supply Characteristics VI - 12
Current Economics VI - 14
HYDROELECTRIC EXPANSION OPTIONS VI - 14
New Developments VI - 15
Power Existing Dams VI - 15
Redevelopment and Expansion VI -15
Restore Retired Power Generating Stations VI - 17
Generator and Turbine Modernization Upgrades VI - 20
Improve Operating Practices VI - 21
Hydroelectric Expansion Costs VI - 22
MARKET CHARACTERISTICS AND CONSTRAINTS VI - 23
Ownership VI - 23
Environmental and Regulatory Constraints VI - 24
Electric Consumers Protection Act of 1986 (ECPA) VI - 24
Off-Umit Rivers VI - 25
Endangered Species Act VI - 25
MARKET ASSESSMENT VI - 25
Costs VI - 28
Air Pollution Prevented VI - 31
VI
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CHAPTER VII: PHOTOVOLTAICS
RESOURCE BASE VII - 2
Base, Accessible, and Reserves VII - 2
Geographic Distribution VII - 2
Seasonal and Daily Variation VII - 4
CONVERSION TO ELECTRICITY VII - 4
Existing Technologies VII - 4
Materials and Cell Types VII - 7
Tracking Systems VII - 9
Current Performance of Actual Systems VII - 9
Current Economics VII -12
Resources Recovered VII -16
EMERGING CONVERSION TECHNOLOGIES VII - 17
Performance/Efficiency VII -17
Costs VII - 20
Potential Technology and Multiple Pathways VII - 20
Manufacturing VII - 20
Materials VII - 21
Cell types VII - 22
Storage VII - 22
Power conditioning, tracking and support structures VII - 22
MARKET ASSESSMENT VII - 22
Costs VII - 26
Air Pollution Prevented VII - 26
CHAPTER VIII: SOLAR THERMAL ELECTRICITY GENERATION
RESOURCE BASE VIII -1
Total U.S. Resources VIII - 1
Geographic Distribution VIII - 2
CONVERSION TO ELECTRICITY VIII - 2
Existing Technologies VIII - 4
Parabolic Troughs VIII - 4
Parabolic Dish Systems VIII - 4
Central Receivers VIII - 8
Solar Ponds VIII - 9
Stand-Alone Systems VIII - 9
Resources Recovered VIII - 11
Current Economics VIII - 11
EMERGING TECHNOLOGIES VIII - 13
Potential Technology and Multiple Pathways VIII - 14
Reflectors VIII -14
Receivers VIII - 14
Solar Ponds VIII -15
Costs VIII -15
VII
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MARKET ASSESSMENT VIII - 16
Costs VIII - 17
Air Pollution Prevented VIII - 21
CHAPTER IX: WINDPOWER
RESOURCE BASE IX -1
Geographic Distribution IX - 2
Seasonal Variation IX - 4
CONVERSION TO ELECTRICITY IX - 4
Conversion Technology IX - 7
Siting and Resource Assessment IX -10
Resources Recovered IX -11
Current Economics IX -12
Intermittent Generation and System Operations IX -14
Land-Use Conflicts IX -16
Remote Transmission Access IX -17
EMERGING CONVERSION TECHNOLOGIES IX - 18
Costs and Performance IX -18
Potential Technology and Multiple Pathways IX -18
MARKET ASSESSMENT IX - 22
Costs IX - 24
Air Pollution Prevented IX - 24
CHAPTER X: INTERMITTENT TECHNOLOGY AND HYBRID/STORAGE
OPTIONS
SUPPLY OPTIONS X - 1
Renewable/Renewable Options X - 2
Renewable/Fossil Options X - 2
Bundled Systems X - 3
Non-Bundled System Options X - 3
DEMAND OPTIONS X - 4
STORAGE OPTIONS X - 5
Conventional and Pumped Storage Hydro X-5
Emerging Storage Options X - 6
Batteries X - 6
Compressed Air Energy Storage (CAES) X - 6
Thermal Storage X - 8
Future Storage Options X - 8
SENSmVfTY ANALYSIS OF AVOIDED COST X - 8
Hybrid Assumptions X - 9
Sensitivity Analysis Results X -10
Windpower X -10
Photovoftaics X -14
Conclusions X -14
EPILOGUE E - 1
viii
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APPENDIX A: RENEWABLE ELECTRIC TECHNOLOGY PENETRATION
SCENARIOS
BIOMASS ELECTRIC SCENARIOS A - 1
Wood. Wood Waste, and Agricultural Waste A -1
Municipal Solid Waste A - 8
Landfill and Digester Gas A -10
GEOTHERMAL SCENARIOS A - 12
HYDROELECTRIC SCENARIOS A - 14
PHOTOVOLTAIC SCENARIOS A - 19
SOLAR THERMAL ELECTRIC SCENARIOS A - 21
WINDPOWER SCENARIOS A - 21
APPENDIX B: 12 REGION MODEL RESULTS
APPENDIX C: MODEL DESCRIPTION
DC
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EXECUTIVE SUMMARY
The purpose of this assessment is to identify the air pollution prevention potential of
renewable electric generation. During recent years environmentalists and members of the renewable
energy community have been hailing the environmental benefits of renewable resources. With
increasing attention on air emissions associated with electricity generation, as well as passage of the
Clean Air Act Amendments of 1990, the U.S. EPA commissioned this analysis to help determine the
near and mid-term potential of renewable electric resources to avoid increased air pollution.
The general approach of the analysis is 'bottoms-up" - that is, technology-by-technology,
region-by-region, and seasonal/time-of-day. In order to assess the emissions reduction potential,
technologies were examined individually based on their cost and operating characteristics in particular
regions (see Appendix C for model description). In addition, the current regulatory and legal settings
were examined closely to help gauge the likely contribution individual technologies could make.
Chapter I provides context by characterizing electricity generation and its relationship to the
environment. Chapter II discusses the technical availability of renewables as well as the institutional
barriers and opportunities. Chapter III integrates the important elements of Chapters I and II with the
technical and regional assessments (discussed in detail in later chapters) to construct a scenario for
increased penetration of renewable electric generation for the years 2000 and 2010. Chapters IV-IX
provide detailed discussions of the current status of the individual technologies. Chapter X offers a
brief discussion of some of the issues associated with the development of "hybrid" technologies, that
are either a renewable/fossil combination, or a renewable/renewable system in tandem.
The assessment leads to the following findings:
1. Renewable electric generation has fewer environmental impacts than fossil fuel-fired
electric generation. Expanded renewable generation can prevent pollution by
displacing fossil fuels. For instance, using hydropower in place of fossil fuel-fired
generation reduces NOX emissions by about 4 kg/MWh based on national averages.
2. Renewable electric generating technologies are already competitive in a variety of
regions and niche markets, providing roughly 370,000 GWh of electricity,
approximately 12% of U.S. electric generation. Hydropower and biomass, both mature
technologies, together account for over 90 percent of this generation.
3. With a few exceptions, renewable electric technologies are at earlier stages of
technological development than fossil fuel competitors. Given the large number of
different pathways and technological options for significant cost reductions, there is a
high probability that some technologies will achieve much wider cost competitiveness
with fossil fuels over the next twenty years.
ES -1
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4. A number of regulatory, economic, environmental and political trends will encourage
increased public and private investment in renewables. Increased investment could
accelerate cost reductions, making renewables more cost-competitive in the near term.
Under conservative assumptions regarding renewable cost reductions through 2010, a
portfolio of renewable 'backstop* technologies for electricity generation will be
available in most U.S. regions at a cost of between 7 0/kWh and 12 c/kWh. With
intensified support consistent with a 'level playing field,' the cost of generating
electricity using renewable resources could fall as low as 4 e/kWh to 7 e/kWh by 2010.
5. While a few states and utilities explicitly include environmental externalities in their
resource planning activities, currently most utility and regulatory practices do not fully
recognize the economic value of renewable electricity sources, thus inhibiting their
market penetration. For example, they fail to reward renewables for preventing
pollution below standards allowed for fossil fuel-fired generation. Some utilities also
undervalue the contribution that renewables can make to minimizing fuel price risks,
as well as minimizing the risks associated with future environmental regulatory
compliance.
6. Innovative ways of integrating intermittent renewable resources such as solar and wind
into electric utility systems could increase their value. These methods could include
fossil fuel hybrid options, portfolio approaches that combine renewable technologies,
demand side management techniques, and electric storage technologies. Current
regulatory or utility practices may not adequately consider the full range of such
options.
7. Renewable technologies have received less government R&D support than fossil fuels
over the past decade. For example, in FY 1990 research for fossil fuels received over
$410 million from OOE compared to about $140 million for renewable technologies.
Additional investment in renewable R&D has the potential to realize larger social
returns compared with fossil fuel R&D.
8. Renewable technology would compete more effectively with fossil competitors if the
environmental benefits of renewable generation were explicitly considered in utility
resource planning. Many PUCs are currently considering incorporating the
environmental costs of fossil fuel-fired generation in the regulatory process.
9. Future economic competitiveness of renewable electric generation will be enhanced by
offering renewable energy sources a 'level playing field* with respect to the recognition
of environmental benefits, greater accommodation of intermittent generation, and
equitable levels of government R&D support.
ES -2
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CHAPTER I
ELECTRICITY GENERATION, ENVIRONMENTAL IMPACT,
AND REGULATION
Expanded renewable electric generation could substantially reduce the amount of air pollution
associated with electricity supply. In fact, this report estimates that substantially expanded use of
renewable electric resources could reduce emissions of NOX and CO2 by 10 percent in the year 2010,
relative to Base Case emissions from all energy sources projected under the National Energy Strategy
(see Chapter III).1 Renewable energy currently accounts for roughly 12% of electricity supply, a
contribution that is expected to grow in the future to the extent that renewable energy costs continue
to fall relative to fossil fuel energy sources. However, the increased use of renewable energy faces
institutional and economic constraints. The prospects for significant increase in renewable electric
generation will depend on how conditions evolve in electricity markets, including guidance by the
policies of federal, state, and local authorities.
This chapter describes how electricity markets operate, highlighting the regulatory trends that
may provide increased opportunities for air pollution prevention strategies. This broad perspective
provides a useful context for understanding how renewable electric generation can help reduce the
environmental impacts associated with energy production and use.
ELECTRICITY AS AN ENERGY SOURCE
Electnciry provides essential services to the economy. Manufacturers, service providers and
households depend on continuous electric power to operate; U.S. industrial productivity and general
quality of life are tied to a reliable supply of electricity. Electric power provides roughly 15% of net
energy consumed in the United States.
Electricity may seem expensive compared with other energy forms, but it provides great value
in the form of light, heat, and mechanical power on demand. Electricity use can be adjusted
instantaneously and requires no storage or inventory, with users paying only for energy actually
consumed. To the end-user electricity entails no direct pollution (as compared to on-site use of coal
1 Similar reductions in S02 (14% of the NES Base Case) are also estimated. Given the current system of
tradeabie SO2 emission permits, however, these reductions would probably not occur. Rather, allowances would
be created that could then be sold to SO2 emitters
I - 1
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or fuel oil). It is therefore viewed by many as the cleanest and most convenient energy form, although
a complete fuel cycle analysis would be needed to determine electricity's total impact.
Sources of Supply
As noted above, electricity is not actually a source of energy, it is a form of energy. In
conventional systems electric current is produced when a generator (dynamo) converts kinetic energy
into electricity; the energy to turn the generator usually comes from the spinning blades of a turbine.
Most electricity in the U.S. is steam-driven, where the primary thermal energy source is fossil fuel
combustion or nuclear energy. Other thermal options include combustion turbines, which are similar
to jet engines, and internal combustion engines.
However, converting fossil energy to electricity entails energy losses of between 60 and 70
percent. Therefore, electricity accounts for greater primary energy use than other forms of direct
energy consumption; in fact, electric power production accounts for 36% of all U.S. primary energy
consumption, with fossil tuels providing two-thirds of the primary energy input. Looking at current
electricity fuel requirements, coal is the dominant fossil fuel, followed by natural gas and oil. Nuclear
power provides 20% of the primary energy. Renewable resources - flowing water (hydroelectric),
biomass fuels (wood and organic waste), geothermal energy, wind, and solar energy - provide the
remaining 12%.2 Table 1-1 shows the current contribution of renewable energy to electricity supply.
Growth in Demand
Figure 1-1 shows historical U.S. .electricity demand and several different projections of electric
demand growth. The growth rate projections range from 1.6% to 2.4% per year through 2010. Based
on these projections and current utility reserve margins, electricity demand during the 1990s will
outstrip current capacity to supply the load in most regions. The primary choices to meet increasing
demand include the following:3
2 DOE/EIA. Annual Energy Outlook 1991
3 Over the time-frame of this analysis, nuclear energy has not been considered. There are a number of issues
associated with nuclear power plant development that are beyond the scope of this report. Given the fact that a
nuclear unit has not been ordered in almost 15 years, and that no utilities have publicly filed their intention build any
new units, this does not appear to be a major omission.
1-2
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TABLE I - 1
RENEWABLE ELECTRIC TECHNOLOGIES: 1990 CONTRIBUTION TO ELECTRIC SUPPLY
Technology
Conventional Hydropower*
Storage
Run-of-nver & diversion
Biomass Electncb
Wood and wood waste0
Municipal solid waste
Landfill and digester gas
Geothermal"
Windb
Solar Thermal Electric*3
Hybrid (natural gas)d
Non-hybrid peaking
Photovoltaics6
Total Renewable Electric
Total U.S. Electric0
Percent Renewable
Capacity
(MW)
71,270
50,380
20,890
7.844
5,728
1,624
492
2,929
1,392
279
274
5
12
83,726
729,400
11.5%
Generation
(GWh)
298,010
197,500
100,510
45,730
32,600
9,250
3,880
23,070
2,190
765
753
12
25
369,790
3,014,000
12.3%
Share of Total
Renewable
Generation
80.6%
12.4%
6.2%
0.6%
0.2%
0.0%
100.0%
Commercial Status
Mature
Mature
Mature
Relatively mature
Relatively mature
Relatively immature
Relatively mature
Relatively immature
Immature
Immature
Notes:
Hydropower data taken from Federal Energy Regulatory Commission (1990) based on average
conditions, excluding Alaska
Based on data contained in The Power of the States (1990, Public Citizen). Generation based
on 65% capacity factor for wood, wood waste, agricultural waste, and municipal solid waste,
and 90% capacity factor for landfill and digester gas.
Includes combustion of agricultural wastes.
See The Power of the States: State-by-State Supplement p. 10.
Capacity and generation taken from Tables A4 and A5 of Annual Energy Outlook 1991 by the
Energy Information Administration. Figures include utility and non-utility capacity and
generation.
I-3
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Conventional and advanced coal power plants;
• Combined-cycle natural gas plants;
• Natural gas turbines (for peak loads);
• Investing in increased efficiency in supply, distribution, or end-use; and
• Renewable electric technologies.
These choices will have important consequences for air quality and the environment. Some
options will increase the amount of air pollution produced each year in the U.S.; others will not.
Because powerplants typically last a minimum of 30 to 40 years, with coal plants lasting for 50 to 60
years with refurbishment, these investment decisions will commit the U.S. to certain levels of air
emissions well into the future.
ELECTRICITY AS A POLLUTION SOURCE
Most of the electricity used in the United States is generated by burning fossil fuels. Thus,
while electricity is a clean and convenient source of power for users, electricity production incurs
environmental costs.
Environmental Impacts
Environmental impacts from electricity generation include air, water, and land pollution which
results from extracting, transporting, and burning fossil fuels. Although this report focuses on the
direct emissions of air pollutants and greenhouse gases, many other impacts arise from the -full fuel
cycle. For example, coal mining operations emit particulates and methane into the atmosphere and
cause water pollution in the form of acid runoff. Coal transport (primarily railroad) consumes energy
and causes pollution. Oil and natural gas drilling and distribution also have environmental impacts.
Although nearly all energy supply activities are regulated to mitigate environmental impacts, damage
to environmental resources and health continue to occur as a result of energy consumption.
Fossil fuels are composed primarily of hydrogen and carbon, but also contain small amounts
of sulfur, nitrogen and other impurities. In an ideal combustion reaction, the hydrocarbon fossil fuels
quickly react with the oxygen in the air (oxidize) to form carbon dioxide (CO2 ) and water, while giving
off useful heat. What is commonly referred to as 'air pollution" results from the incomplete combustion
1-5
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of hydrocarbon fuels (forming carbon monoxide, CO), the presence of impurities in the fuel (such as
sulfur that forms sulfur dioxide, SO2) or high combustion temperatures (which convert atmospheric or
fuel-based nitrogen into nitrogen oxides, NOX).
Air Emissions and Environmental Controls
Regulated Pollutants. Under authority of the Clean Air Act of 1970, the U.S. Environmental Protection
Agency (EPA) has established ambient air quality standards for a number of air pollutants. These
•criteria' pollutants include SO2 , NOX , CO, paniculate matter, and reactive volatile organic
compounds (VOCs). The EPA and individual states then set emission limits for individual stationary
sources. Table I-2 shows the progress made in controlling pollutants from electricity generation
between 1970 and 1988. During this period, overall emissions of air pollutants from electricity
generation have gradually fallen, while electricity generation has increased by 77%. Despite these
accomplishments, fossil fuel-fired electricity generation accounts for about 66% of total U.S emissions
of sulfur oxides, 37% of total emissions of nitrogen oxides, 6% of total paniculate emissions, and less
than 1% of total VOC and carbon monoxide emissions.4 Figure I-2 shows 1989 emissions of EPA's
criteria air pollutants from U.S. electric utilities.
Sulfur Dioxide. SO2 emissions from electric utilities peaked in the mid 1970s at nearly 17 million
metric tons per year and currently stand at 14 million metric tons (66% of total U.S. SO2 emissions).
S02 can adversely affect human health and is the primary constituent of acid rain, which harms
aquatic and terrestrial ecosystems. Over 95% of SO2 emissions from electricity generation come from
coal-fired facilities. New coal-fired utility sources are controlled with "scrubbers," which range in cost
between $70 and $250 per kilowatt ($120/kW average) and remove up to 95% of SO2 from the flue
gases.5 Because of concern about SO2 emissions from existing utility sources, the Clean Air Act
Amendments of 1990 will limit overall annual SO2 emissions from electricity generation to about 8
million metric tons by 2000. This emission 'cap' will be sustained by a system of allowances that can
be traded among emitters.
Nitrogen Oxides. NOX emissions from utilities have increased from 4.4 million metric tons in 1970 to
7.3 million metric tons in 1989, an average annual growth rate of 1.7%. Utilities accounted for 37% of
4 See National Air Pollutant Emissions Estimates, 1940-1989, Environmental Protection Agency. Tables 7-11.
5 See Electric Power Annual 1989 (Energy Information Agency, 1991) Table 47. Some of these technologies do
not eliminate pollution, but simply transfer pollutants to other media. For example, scrubber sludge must be
landfilled carefully to prevent groundwater pollution However, the pollutants may be more easily controlled in this
form where they are more concentrated and less reactive.
I-6
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TABLE I - 2
CRITERIA POLLUTANTS: 1970, 1980, 1989
(Thousand Metric Tons/Year)
PARTICULATE
Coal
O.I
Gas
Total Utility
TOTAL PARTICULATE
SULFUR OXIDES
Coal
Oil
Ga*
Total Utility
TOTAL SULFUR OXIDES
NfTROGEN OXIDES
Coal
Oil
Gas
Total Utility
TOTAL NITROGEN OXIDES
VOC
Coal
Oil
Gas
Total Utility
TOTAL VOC
CARBON MONOXIDE
Coal
Oil
Gas
Total Utility
TOTAL CARBON MONOXIDE
Source EPA/OAQPS. 'National Air
March 1991. Tables 19-20
1970
2,220
110
6
2,336
18,548
1970
14,330
1,450
1
15,781
28,422
1970
3,170
390
880
4.440
18.510
1970
20
7
5
32
24.951
1970
100
40
80
220
101.420
Pollutant Emission
1980
720
100
6
826
8,522
1980
14,190
1,300
1
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23,377
1980
5,150
440
780
6,370
20,919
1980
30
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21,117
1980
170
40
80
290
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Estimates, 1989'
1989
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7,154
1989
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678
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1989
6,430
280
585
7,295
19,887
1989
38
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1989
230
30
60
320
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U.S. NO emissions in 1989. NOV is also a precursor to acid rain. In combination with volatile organic
X A
compounds (VOCs), NOX forms tropospheric ozone (photochemical smog), which causes respiratory
stress and other health problems. Low-NOx burners can reduce NOX formation by 50% from utility
boilers, and more expensive selective catalytic reduction can remove about 90% of NOX from the flue
gas. The Clean Air Act Amendments of 1990 will reduce annual utility NOX emissions to about 4.6
million metric tons by 2000.
Paniculate Matter. Paniculate emissions from electric utility generation have been steadily declining
from 2.3 million metric tons in 1970 to 0.4 million metric tons in 1989, or 6% of total U.S. emissions.
Particulates impair visibility and contribute to respiratory problems. Baghouse filters and electrostatic
precipctators remove over 99% of paniculate matter, and nearly all coal-fired sources apply these
measures.
Carbon Monoxide. CO emissions are harmful to human health. CO emissions from oil and gas-fired
generation facilities have decreased since 1970. but CO emissions from coal-fired generation have
more than doubled. As a result, total CO emissions from electric generation rose from 0.2 million
metric tons in 1970 to 0.3 million metric tons in 1989, a 40% increase. Putting this increase in
perspective, utility CO emissions represented only 0.5% of the U.S. total in 1989.6
Volatile Organic Compounds. Non-methane volatile organic compounds (VOCs) are si broad class of
pollutants that include evaporated gasoline, unbumed hydrocarbons emitted from automobile engines,
and a wide range of industrial and home solvents. These VOCs contribute to tropospheric ozone
pollution. Total VOC emissions from electric generation have increased slightly from 32,000 tons in
1970 to 46,000 tons in 1989; coal VOC emissions have doubled over the same period. Utilities,
however, directly contribute minor amounts (0.2%) to national VOC emissions.7
Unregulated Pollutants. Greenhouse gases, including carbon dioxide and methane, currently are not
regulated by the EPA as criteria pollutants. They are included in this analysis, however, because
utilities account for a significant portion of these emissions.
Carbon Dioxide. Although carbon dioxide is not regulated as a criteria pollutant, C02 is the primary
•greenhouse gas* contributing to global warming. The amount of CO2 released in combustion is
related to the ratio of carbon to hydrogen in the fuel. Figure I-3 shows the molecular structure of coal
6 The vast majority of CO emissions (66%) comes from transportation sources.
7 Transportation and industrial processes account for 35% and 44%, respectively, of total VOC emissions
I-9
-------
FIGURE I - 3
MOLECULAR STRUCTURES OF COAL AND METHANE
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1-10
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and methane (the primary constituent of natural gas). Coal emits about twice as much carbon per
unit of heat released as does natural gas. The CO2 emission rate for oil combustion is between that
of coal and natural gas.
No practical abatement technologies exist to control CO2 from carbon-based fuels, and C02
emissions from electric utilities will rise if current trends continue. In 1988, electric utilities in the U.S.
emitted 1.800 million metric tons of CO2 , or 37% of U.S. CO2 emissions.8 U.S. electric utilities
account for roughly 8% of worldwide CO2 emissions. Over half of the electric power in the U.S. is
generated from coaJ, and many forecasts project that the contribution of coal to U.S. electric power
generation will continue to grow over the next decades. If coal remains the dominant electric
generation fuel, then utility CO2 emissions could account for even larger shares of total U.S. CO2
emissions. For example, Figure I-4 shows the CO2 emissions from a recent forecast made by the
Energy Information Administration, where emission from all electric generation (utility and non-utility)
increases roughly 75% over the next twenty years.9
Methane. Methane reacts more slowly than other hydrocarbons to form ozone, and is not included in
the class of regulated VOCs. However, methane is a powerful greenhouse gas that contributes to
global warming. As with other VOCs, utilities are directly responsible for a very small share of total
methane emissions. However, natural gas extraction operations and pipelines that supply utilities with
natural gas may contribute methane to the atmosphere, and coal mining operations routinely vent
methane for safety reasons.
ELECTRICITY SUPPLY AND REGULATION
The most attractive feature of electricity - instantaneous power on demand - makes electricity
supply a complex undertaking. Electric utilities must continually adjust electric supply to meet
fluctuations in demand. Much of the demand follows fairty predictable patterns. For example, daily
peak demand occurs during relatively predictable times in most utility systems, and utilities can
anticipate increased air conditioning loads during hot summer days. However, other fluctuations are
more random.
In order to provide reliable power, utilities must control the output of a mix of generating units
to keep the system operating within certain parameters (e.g. voltage and frequency). Controlling the
8 DOE/EIA. Electric Power Annual. 1988, Table 30. In addition to electric utilities, non-utility electricity
generation emitted about 200 million metric tons of CO2
9 Figure 1-4 is derived from forecast in Annual Energy Outlook 1990. DOE/EIA-0383(90).
1-11
-------
FIGURE I - 4
CO2 EMISSIONS BY TYPE
FROM ELECTRICITY GENERATION
4,000
2010
Coal
Source: Energy Information Administration
Petroleum
Gas
1-12
-------
output of these units to supply power in the least expensive manner is called economic dispatch.
Baseload plants (usually coal, nuclear, and hydroelectric capacity) operate continuously unless shut
down for repair; intermediate load plants are cycled (generation varies through the day) or generate
only during high demand seasons; and peaking units (usually natural gas turbines or internal
combustion engines) are operated only for a few hours per day in the high demand season. In the
short run, utility operation focuses on economic dispatch and maintaining generating units to keep
them operational. Utilities must also maintain a cushion of reserve capacity to accommodate higher
than anticipated demands and unscheduled shutdowns of generating units. Over the long run,
utilities must decide how to meet growth in demand for electricity and maintain reserve margins. A
utility's portfolio of power plants changes as new resources are required to meet growing loads, and
as older generating units are overhauled or replaced by new, more efficient technologies.
Some renewable energy sources -- hydroelectric, solar, and wind - cannot always provide
dispatchable power due to the intermittent nature of the resources. These technical considerations
pose some challenges to utility operations. The operation of specific renewable electric technologies
are discussed in individual chapters, and Chapter X explores ways that intermittent renewable electric
generation can be integrated into electric supply systems.
Rate Regulation and Traditional Supply Decisions
About 80% of U.S. electricity is generated by investor-owned utilities (lOUs), which operate
under the rules and conditions set forth by the state Public Utility Commissions (PUCs).10 Under the
traditional regulatory compact. lOUs accept an obligation to provide reliable power on demand under
electricity rates set by the PUC, in exchange for a monopoly license to generate, transmit, and
distribute electric power within a specified service territory. The PUC sets electricity rates based on
the operating and capital costs incurred in meeting service obligations (including an allowed return on
investment), providing that the utility is investing prudently and operating efficiently.
Historically, electric utilities have responded to projected demand growth by constructing large
central-station generating plants. Fuel choice was based on the type of capacity needed, regional fuel
availability, and relative cost. After the PUC granted a 'Certificate of Need" for a new generating
facility, the utility constructed the powerplant. If upon completion of the plant the PUC determines that
10 Various government agencies also generate and distribute electric power. For example, the federal
government owns and operates about 65 GW (9%) of U S. generating capacity, of which 40 GW is hydroelectric.
States, district and regional authorities, counties, and municipalities own 2,000 utilities (about 10% of total capacity),
and about 900 consumer-owned cooperatives (about 4% of capacity) also supply electricity. See Electric Power
Annual 1989. DOE/EIA. pp 2-3
I - 13
-------
the investment in the plant was prudent, the cost is then allowed into the "rate base,' and the utility
customers begin paying for it through electricity rates. Beyond conforming with federal and state
environmental regulations and local pollution control or land-use ordinances, the environmental
impacts of powerplant emissions are often not considered in traditional supply planning processes.
Demand-Side Options
Over the past fifteen years, utility planners have begun to develop programs to influence
electricity demand as an alternative to building new supplies. These programs, called 'demand-side
management* (DSM). have been encouraged by PUCs and intervenors concerned about the rate
impacts of adding increasingly expensive generating capacity. In utility DSM programs, utilities
encourage investment in more efficient end-use technologies that can deliver the same level of electric
services, such as light, heat, and mechanical power, while using less electricity. Typical program
elements include direct investment by offering customer rebates for efficient appliances, lighting, or
industrial motors; performing energy audits; and offering energy planning assistance or information. If
enough consumers purchase efficient equipment in response to the incentives, then demand for
electricity will not rise as quickly. These efficiency gains become a source of electricity "supply" that
can be used to satisfy new demands for electric services, enabling utilities and ratepayers to avoid the
costs of building new powerplants.
Many PUCs have required DSM evaluation as part of the normal supply planning process, a
marked departure from the historical scope of PUC oversight. Where PUCs traditionally evaluated the
economic viability of completed generating facilities, many PUCs now insist that utilities examine
demand side measures prior to investing in generating capacity, a process known as least cost utility
planning (LCUP) or integrated resource planning (IRP).
Emerging Competition and Supply Choices
The 1980s ushered in a period of growing non-utility investment in generation capacity. The
emergence of non-utility owned power plants has ignited an extensive debate over the role of
competition in electricity supply. The appropriate role of bidding, transmission access, and the
influence of PUCs on investment decisions are among the issues that cloud the future of electricity
markets in general, and renewable generation in particular. The outcome of this debate will
determine, among other things, whether renewables can compete on a "level playing field" in which
the environmental impacts of renewable electric generation are appropriately compared with the
impact on the environment from fossil fuel generation.
I- 14
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Qualifying Facilities under PURPA. The Public Utilities Regulatory Policies Act (PURPA) of 1978
guaranteed a market for renewable power producers and cogenerators (facilities that produce
electricity in conjunction with steam or waste heat) under certain conditions. PURPA was designed to
create opportunities for non-utility energy developers to participate in the electric power market, and
remains the regulatory foundation upon which most emerging renewable electric projects are built and
operated. PURPA was quite successful in stimulating renewable energy development during the
1980s, as seen in Figure I-5. Under PURPA, renewable power and cogeneration projects are
designated "Qualifying Facilities" (QFs) under rules established by the Federal Energy Regulatory
Commission (FERC).11 Utilities are required by law to purchase power from QFs and sell back-up
power to QFs at non-discriminatory rates. The state PUCs set the electric power purchase rates at the
avoided cost" of the utility. PURPA grants states broad latitude in establishing the markets for QF
generators, and a wide variety of approaches has emerged.
Although definitive statistics are not available, QFs account for most of the non-hydroelectric
renewable electric capacity. Nearly all windpower and solar thermal capacity is non-utility owned, and
about 65% of biomass capacity and 80% of geothermal capacity is non-utility owned. Private non-
utility conventional hydropower represents only about 2% of the U.S. capacity.12
Independent Power Producers. Independent power producers (IPPs) are a rapidly growing class of
non-utility private power developers that are not QFs under PURPA. In practice, IPPs resemble utility-
owned generators except for the ownership and contractual relationship between the IPP and utility.
IPPs can use any fuel and build generating capacity of any size, and thus have some inherent
competitive advantages over renewable QFs, although IPPs are not guaranteed avoided cost
payments.
Competitive Procurement and Bidding. Utilities in several states have also established competitive
bidding procedures for acquiring new capacity. The bidding process allows non-utility generators
(and sometimes demand-side options) to compete for investments in new capacity expansion needs.
Non-price factors, such as reliability, project viability, location, size, technology, and environmental
impact are also evaluated for individual power supply bids. While early experience in competitive
procurement has not been favorable for renewable energy developers, state regulators are beginning
11 A renewable QF must derive at least 75% of energy input from a renewable energy source. An 80 megawatt
(MW) size limitation on solar, wind, and geothermal projects was lifted in 1990 No size limit applies to
cogeneration facilities Cogenerators can use any fuel, but at least 5% of the energy input must be consumed for
non-electric use,
12 See Susan Williams and Kevin Porter, Power Plays: Profiles of America's Independent Renewable Electric
Developers, (Investor Responsibility Research Center, 1989), p. 15.
I- 15
-------
FIGURE 1-5
Renewable Energy Capacity Additions
IRRC Profiled Companies
Thousands of megawatts
10
8
N«w additions
Existing capacity
1979
1981
1983 1985 1987 1989
1991
1993
Note: Pre-1960 data is cumulative.
Note: Post-1988 data is projected.
Source: Investor Reap. Research Center
Source: Power Plays Profiles of Americas Independent Renewable Electric
Developers, by Susan Williams and Kevin Porter (Investor Responsibility
Research Center. 1989). p 25
I - 16
-------
to examine ways to increase the renewable energy share by assigning greater weight to non-price
factors or setting aside capacity blocks for renewables.
Current and Planned Capacity
As of 1990, electric utilities in the U.S. had 690 gigawatts (GW) of generating capacity, with an
additional 40 GW owned by non-utility generators.13 The total capacity of 730 GW generated over 3
million gigawatthours in 1990. According to the Energy Information Administration, utilities have
already planned to add 368 generators with a combined capacity of 41.2 GW between 1990 and 1999.
These additions include 208 gas- or oil-fired units (14.9 GW), 39 coal-fired units (15.8 GW), 5 nuclear
plants (5.8 GW) 100 hydroelectric generators (3.5 GW) and 16 "other" -- mostly renewable -- units (1.2
GW). Figure I-6 presents this breakout of planned capacity additions. Most of the announced
capacity has not begun construction. In addition, EIA projects that utilities and non-utility generators
will build an additional 66 GW of currently unannounced capacity by 2000, of which 52 GW will be
natural gas-fired.14
REGULATION AND POLLUTION PREVENTION IN ELECTRICITY GENERATION
The two regulatory frameworks that govern electricity supply - rate regulation and
environmental control -- have traditionally operated as constraints on electric power generation.
Environmental regulation constrained certain operating and investment decisions based on
environmental impacts, while rate regulation constrains electricity prices and costs. These regulatory
systems attempt to address different types of market failure: rate regulation checks the power of
natural monopolies, and environmental regulation limits the adverse impact of electricity generation on
human health and ecological resources.
Over the past 20 years, the control of EPA criteria ambient air pollutants from electricity
generation has evolved into a complex system of ambient standards, emission limits, and permits.
These current regulatory systems give no credit for actions that reduce unregulated pollutants such as
CO2 or CH4. Taken together, these regulations allow an "acceptable" amount of pollution from the
production of electricity. The role of environmental regulation is to establish and enforce the amount
13 Energy Information Administration Annual Energy Outlook 1991, Table A5. A Watt is a measure of power or
capacity One kilowatt (kW) is 1,000 Watts, a megawatt (MW) is 1,000 kW, and a gigawatt (GW) is 1,000 MW. A
kilowatthour (kWh) is a measure of energy equal to one kW of power over an hour. A megawatthour (MWh) is
1,000 kWh, and a gigawatthour (GWh) is 1,000 MWh As a rule of thumb, 1 MW of capacity can serve roughly
1,000 residences (assuming residential demand at 6,000 kWh/year and capacity operating at 68% capacity factor).
14 Energy Information Administration, Electric Power Annual 1989 (January, 1991) pp. 23-33.
I - 17
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of socially acceptable pollution at the time the regulation is put forth. What constitutes "socially
acceptable' is determined by the scientific data available at the time a law is passed or a regulation is
promulgated and the willingness of society to adopt a certain law or regulation. As new data become
available, or as public attitudes shift, the 'socially acceptable' amount of pollution may change.
Historically, the full environmental impact of generating options has not been considered in
electricity investment decisions. A generating plant that produces no emissions (or emissions below
the allowable limit) in most cases receives no additional credit compared to one that meets the
emissions limit, even though the additional reductions may help to meet an ambient standard that
required additional reductions elsewhere. Thus, a renewable plant with emissions far below the plant
rt competes against could reduce emissions even more than required, yet under the rate-setting
system its higher cost would get no credit for additional pollution reduced compared to its competitor.
In this instance it »s possible that the resource chosen by the utility and approved by a PUC could
lead to more stringent emission limits on other polluting activities that could result in higher total costs
and greater pollution for society compared to an investment in the renewable plant. Thus, some
opportunities for reduced pollution are not reflected in traditional environmental or regulatory planning
activities.15
The Pollution Prevention Approach
The pollution prevention approach recognizes that altering activities (e.g. production
processes) can often reduce the amount of pollution produced. Instead of applying control
technologies to the stack' or 'on the tailpipe' to clean up emissions, it may be possible and more
cost-effective to prevent pollution in the first place. Pollution prevention can reduce or eliminate three
costs the cost of controlling the amount of pollution entering environmental media, the environmental
damage that occurs from pollution actually emitted, and the cost to the government of regulations to
control the pollutants. Because traditional regulation focuses on establishing and enforcing an
acceptable emission level, existing regulations may not recognize or encourage fundamental changes.
However, in many cases pollution prevention costs less than building emission controls and fixing the
environmental damage that occurs under the traditional regulatory approach. Over the long run,
pollution prevention is often less expensive than suffering environmental damages, mitigating adverse
environmental impacts, or imposing additional controls.
15 For acid rain reduction, a new system is being set up to achieve lower emission limits in which reductions by
generating facilities below the 'allowance' given to current units would be used as credits to offset emissions
elsewhere
I - 19
-------
The pollution prevention approach views electricity as a means of providing beneficial services
such as light, heat, and mechanical power. These same services - though not necessarily fossil-fuel
generated electricity -- could be provided in a more environmentally benign way if the full range of
technological options were considered. For example, the same level of services could be attained
with much less electricity if consumers bought the most energy efficient end-use equipment, such as
lights and appliances, instead of equipment with average efficiency. This would prevent pollution by
reducing the amount of generation required to provide the services.16
Many recent studies have identified vast potential for reducing electric demand by increasing
end-use efficiency.17 Depending on the analysis, between 20% and 45% of current (or projected)
electricity consumption could be avoided by adopting the most efficient end-use technologies. Utility
DSM programs target the cost-effective portion of this "supply," but do not necessarily take into
account the pollution prevention benefits. Thus, while the emergence of DSM programs represents an
historic shift toward pollution prevention, the emphasis on traditional economic impact on ratepayers
and shareholders may limit the extent to which conventional DSM programs may prevent pollution.
Moreover, increased efficiency can reduce, but not eliminate, the need for electric power. Thus,
society still must choose among the technologies that provide electricity.
Pollution Prevention. External Costs, and Renewable Energy
Adopting the pollution prevention approach in the electric generating sector would encourage
generating options that produce the needed electricity with the least pollution. Renewable energy
sources produce much less air pollution than conventional fossil alternatives. Figure I-7 shows how
much air pollution an advanced technology coal-fired generating facility will create per gigawatthour of
electricity generated, compared with a photovoltaic generating plant. Advanced natural gas
generating facilities would produce significantly less air pollution than would a coal-fired facility, and
some renewable energy technologies would produce more air pollutants than PV stations. However,
most renewable electric technologies produce far fewer air pollutants than fossil fuel electric
generation.
16 Other changes in energy use could prevent pollution, such as substituting direct natural gas for some uses
currently served by electricity Since only about a third of the energy consumed in the production of electricity is
returned as electric power, significant energy and pollution savings can be realized when direct fuel use can
provide services with less energy lost
17 See Energy Efficiency How Far Can We Go' by Roger Carlsmith, et al, prepared by Oak Ridge National
Laboratory for the Office of Policy. Planning, and Analysis, u S DOE. 1990; Efficient Electricity Use: Estimates of
Maximum Energy Savings by the Electric Power Research Institute. 1990, and The Potential for Electricity
Conservation in New York State, prepared for the New York State Energy Research Development Authority, 1989
I -20
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To the extent that renewable electric generating technologies displace fossil fuel-fired
generation sources, these technologies would prevent air pollution. The major issue concerning the
promotion of renewable energy is its cost relative to conventional alternatives. Most renewable electric
technologies are currently more expensive than fossil technologies, as measured by market prices.
However, market prices for fossil fuels do not reflect all of the environmental damages that result from
their use. Economists call these damages 'externalities,11 reflecting the notion that users of fossil fuels
do not pay the full social cost of their choices (some costs remain external to their decision). If the
price of fossil fuels included the external costs of environmental damages, many renewable energy
alternatives become economically competitive with fossil fuel energy sources. This analysis projects
the potential impact of quantifying carbon-related externalities and shows that, depending on the level,
this valuation can significantly affect the ability of renewables to compete with fossil alternatives (see
Chapter III - Externality Penalty Cases).
Figures 1-8 and 1-9 show a range of recent estimates of damages from pollutants and
greenhouse gases arising from fossil fuel generation, on a per ton basis. Table 1-3 summarizes
several recent studies that quantify the external cost of electricity generation in cents per kilowatthour
generated. The high social cost of fossil fuel electricity supply is another way of expressing the
pollution prevention rationale for promoting renewable energy. Despite continued disagreement over
the precise level of environmental damages from fossil fuel combustion, many analysts agree that
these externalities are sufficiently large to be an important factor in rational economic choices
regarding energy supply. Once quantified and incorporated into energy supply decisions, the external
costs of fossil fuel electricity generation will enhance the market prospects of renewable energy
resources.
REGULATORY REFORM AND RENEWABLE ELECTRIC OPPORTUNITIES
Rate regulation and environmental regulation continue to evolve. The inclusion of demand-
side options into the electric resource planning has been an important step toward pollution
prevention. Integrated resource planning methods can be extended to give more explicit recognition
of the pollution impacts of various supply and demand choices, and rate regulators are examining
several ways to incorporate environmental impacts into the regulatory planning process. Regulators
are also beginning to examine how costs at the time of initial investment and the risks of future
environmental controls and fuel supply should influence resource selection. On the environmental
regulation side, elements of the Clean Air Act Amendments of 1990 reinforce these trends by adopting
market-based mechanisms to allocate emission controls.
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Integrated Resource Planning and Pollution Prevention
Utility investment decisions are increasingly influenced by state legislatures, regional planning
authorities, and PUCs. Many state regulators have adopted the integrated resource planning
framework to guide resource selection, and most states have at least considered this approach.
Several states have ordered the explicit consideration of environmental externalities in IRP, notably in
Massachusetts, New York, Oregon, Vermont, and Wisconsin.18 Incorporating environmental impacts
into IRP transforms least cost utility planning into least social cost utility planning, a more radical
departure from the traditional utility regulatory objectives of reliability and low rates. Table I-4 shows
which states are currently examining or implementing environmental criteria for air and water
pollutants, and land-use impacts.
The environmental externalities associated with certain technologies are being assigned dollar
values (or points in bidding systems) to account for environmental mitigation, health, and other costs
over the long term. These externalities are then weighed in decisions between electric efficiency and
vanous supply options. The effect is that the long-term externalities associated with a particular
technology will be reflected in the initial cost, so that the advantages of technologies causing little
environmental harm (e.g. conservation investments and renewable generation) would be considered in
economic choices. When social costs govern investment decisions in an IRP framework, pollution
prevention criteria influence utility resource selections.
Direct Environmental Valuation. Along with conventional cost data for demand and supply options,
the IRP framework can accommodate environmental impacts. The most direct approach (from the
perspective of IRP methodology) would be to assign dollar values for environmental damages from
each option and simply count these costs in the conventional manner. California, New York,
Massachusetts and other states are examining direct valuation approaches. Table I-5 shows
proposed values of external cost valuation used in utility resource planning. The effect of these values
on coal and geothermal generation costs in California are presented in Table I-6.
There are several methods used to value environmental externalities. The two most common
approaches are to base external costs on estimated environmental damage or to value emissions on
1A
The diversity of state programs to incorporate environmental externalities is documented in Chapter X of
Environmental Costs of Electricity, prepared by the Pace University Center for Environmental Legal Studies (New
York Oceana Publications, Inc , 1990)
1-27
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TABLE I - 6
THE EFFECT OF PROPOSED EXTERNALITY VALUES ON
COAL AND GEOTHERMAL GENERATION COSTS IN CALIFORNIA
(levelized 1990c/kWh)
COAL GEOTHERMAL
Estimated Levelized Cost 5.0 - 6.6
Externality Valuations
SO2 1.3
NOX 2.0
TSP 0.1
VOCs <0.1
CO2 0.8
Total Generation Cost 9.3 - 10.9
2.4 - 7.9
0.0
0.0
0.0
0.0
0- <0.1
2.4 - 8.0
Sources: Estimated levelized bid pnces and emission rates for representative coal and
geothermal plants are presented in What Contribution can Environmental
Valuation Make to the Cost Competitiveness of Renewables in Current Bidding
Systems for the Electricity Business?, prepared for EPA by Boston Pacific
Company, Inc., Council for Renewable Energy Education, and ICF
Incorporated. June 1991. The lower bound of coal costs does not come from
this source, but is estimated based on inputs to the Renewable Electric Model
used in the current study.
I -30
-------
the marginal costs of controls.19 As discussed above, however, current environmental valuation
techniques are subject to much uncertainty. The scope of environmental valuation also affects the
results. For example, complete analysis of entire fuel cycles (i.e extraction, distribution, combustion,
and by-product management) gives a broader picture of environmental impact than an analysis of air
emission impacts. Such studies are more expensive to perform and introduce additional uncertainty
in the results
Other Valuation Options. Environmental factors could be incorporated into the competitive electric
suppfy sector through environmental penalties for fossil fuel QFs or bid evaluation criteria. Instead of
explicit environmental valuation, blocks of proposed capacity could be set aside for environmentally
benign technologies such as conservation and renewables, either in utility plans or in competitive
procurement. This would ensure that at least some capacity would be built with minimal
environmental impact
For example, the California Energy Commission recently proposed to mandate that
renewables provide half of new capacity needs over the next ten years. The Bonneville Power
Administration grants preferential treatment in planning and competitive bid evaluation in the form of a
10% cost advantage for conservation and renewables. As a result of its recent 'Green RFP' bid
solicitation, New England Power Company expects to purchase up to 200 GWh of electricity annually
from renewable energy sources. A review of utility competitive procurement experience found that
environmental factors were given up to 15% of the total points in recent (self-scoring) request for
proposals.20
Allocation of Future Regulatory and Cost Risk
Utility planning is inherently uncertain. Since electricity demand, fuel prices, future regulatory
requirements, and emerging technology performance cannot be predicted with accuracy, regulators
and utilities must rely on projections of future outcomes to make rational technology choices. Such
choices implicitly expose ratepayers, utility shareholders, and environmental resources to different
risks.
19 Valuation based on the marginal cost of controls is sometimes referred to as the "revealed preference'
approach, because the marginal control cost reflects the value that society (or regulators) currently attaches to
environmental protection under existing regulatory policy
3O
See Competitive Procurement of Electric Utility Resources, prepared for the Electric Power Research
Institute. (EPRI CU-6898) July, 1990, pp 97-98
1-31
-------
Fuel Price Risk. Utility planners must use projections of future fuel prices in order to choose the most
economic generating technologies. These projections are subject to PUC approval, but subsequent
fuel price risk is generally borne by ratepayers through automatic fuel adjustment clauses. These
were introduced in the 1970s to reduce the need for PUC rate-setting procedures during times of
volatile fuel prices. In practice, this means that higher or lower fuel costs are directly passed on to
consumers in the form of increased or lowered electricity rates, thereby insulating utilities from the
risks associated with future fuel price volatility. As a result, utilities may have different perceptions of
fuel price risk than consumers. To the extent that utilities discount the possibility of higher or volatile
fuel prices because they can pass on the increased costs, technology choices will be biased against
generating options like the renewable technologies that have low, stable, or virtually zero (in the case
of solar and wind) fuel prices. Alternatively, to the extent that utilities and PUCs attach value to fuel
diversity to lower risks from fuel price volatility, renewable energy sources would be favored over
fossil-fired plants.
Regulatory Risk. The potential for more stringent environmental requirements could encourage
utilities to choose options with fewer environmental impacts. Beyond conforming to existing
environmental laws and regulation when making capacity decisions, utilities might also consider the
potential for increased restrictions. Since fossil fuel generating facilities are long-lived, future
environmental initiatives - such as fossil fuel taxes (on a CO2 or Btu basis) or CO2 reduction targets -
would reduce the value of fossil fuel generating capacity and require additional investments to meet
the demand for electrical services. Although not formally considered in traditional rate regulation, if
the risk of incurring such costs can be reflected in the costs of those generating options most likely to
face additional requirements, supply choices may tilt toward more environmentally benign
technologies.
An alternative approach to explicitly considenng risk now is to judge prudency of decisions
later. If new regulations were required to address environmental concerns that arise in the future,
PUCs could increase electric rates to cover the additional abatement expense. One possibility would
have PUCs consider not allowing utilities to recover the full capital investment in fossil plants through
higher rates if they determine that utilities should have anticipated such risks. For example, Figure I-
10 presents an open letter to the U.S. utility industry from the National Association of State Utility
Consumer Advocates and a coalition of environmental groups warning utilities that they will oppose
future rate increases associated with reducing greenhouse gases if steps are not taken immediately to
account for these risks in their long-term planning. Given these possible outcomes, utilities could
begin to plan to minimize potential 'regret' as compared with minimizing current and projected costs,
by including the additional costs of potential CO2 restrictions into current resource planning.
I-32
-------
FIGURE 1-10
AN OPEN LETTER TO THE MANAGERS OF THE U.S. UTILITY INDUSTRY
Re: Implications of the Greenhouse Challenge for Utility Planning, Financial Risks, and Future Prudency Reviews
Dear Colleague:
This letter is a pint product of two communities with extensive involvement in utility issues: consumer advocates and
environmental organizations. Recent scientific and policy developments convince us that the utility industry should be put
on notice that its resource planning must take into account risks associated with continuing growth in greenhouse gas
emissions. Our decision is based on a growing scientific consensus on the need to reduce emissions of greenhouse gases,
as exemplified in recent reports from the Intergovernmental Panel on Climate Change (IPCC).
The IPCC" is the broadly representative international body charged by the U.S. and other governments with assessing
prospects for global climate change. It has now determined that human activities are substantially increasing the
atmospheric concentrations of greenhouse gases; that these increases will warm the earth's surface; and that "business as
usual* emissions will result in a warming during the next century that is greater than that seen over the past 10,000 years.
The IPCC cannot rule out surprises that might worsen or moderate this trend, but it calculates with confidence that
substantial reductions in current emissions of carbon dioxide and other greenhouse gases would be necessary to stabilize
their concentrations in the atmosphere. The United States is the world's largest source of these emissions. Other major
nations arc already moving to stabilize or reduce carbon dioxide releases; examples include Germany, the United
Kingdom, Japan. Denmark, and the Netherlands.
We do not pretend to be able to chart the future of the l-arth's climate. We are convinced, however, that findings like
those of the IPCC should prompt the utility industry to reassess its strategic plans to account for increased risks of fossil
fuel use. Such findings will also likely result in steadily increasing international pressures to reduce fossil fuel use both
here and abroad. Those pressures, in turn, suggest several likely consequences. For example, utilities contemplating
substantial investments in long-lived fossil fuel technology should begin explicitly to take these risks into account, both in
assessing these technologies and in evaluating alternatives. Second, failure to realign resource planning and investment in
this way will open those responsible to prudency challenges, if identified risks and alternatives are not responsibly
addressed. Third, utility plant exteasion and refurbishment programs may become less attractive compared with energy
efficiency improvements and renewable energy resources.
As the most substantial sources of carbon dioxide per unit of energy produced, coal- and oil-fired generation clearly merit
the closest scrutiny in terms of greenhouse risks. Both for new unus and long-lrved extensions of existing units, an
invigorated search for alternatives clearly is needed. However, we do not believe that this imperative will or should result
in a nuclear power revival, since thai technology still fails tests of financial risk and cost-effectiveness. Its lower carbon
dioxide emissions are unlikely by themselves to reassure investors. Moreover, still unresolved problems, including those
related to high level nuclear radioactive waste disposal, can not he ignored. This conclusion is reinforced by an
abundance of preferable alternatives on both economic and environmental grounds, including efficiency improvements in
all sectors of energy use and numerous renewable energy technologies.
Ratepayers' income, utility shareholder investments, and environmental quality will all be at risk, if the utility industry fails
to take into account future costs of greenhouse gas emissions in its resource planning. Conversely, all of our constituents
stand to gam when utilities cost-effectively substitute whai amount to climate defense technologies for additional
greenhouse pas emissions. We jointly pledge our bcsi efforts in helping regulators to gauge utilities' performance and to
respond appropriately.
Sincerely,
Donna Sorgi, President John Adams, I-jcecutive Director
NASUCA Natural Resources Defense Council
IW 15th Street. NW 40 West 20th Street
Suite 575 New York, NY 10011
Washington. DC 20005
I -33
-------
Recently, the Southern California Edison (SCE) and Los Angeles Department of Water and
Power (LADWP) announced their intentions to reduce emissions of C02 by 20% over the next twenty
years.21 The president of SCE stated explicitly that taking prudent steps today to reduce CO2
emissions will ensure we have no regrets later if scientific research confirms that CO2 and other
greenhouse gases in fact do cause global warming.1 In Wisconsin, the Public Service Commission
requires utilities to conduct sensitivity analysis on resource plans to determine the costs of future CO2
limits, assuming that CO2 is reduced by 20% from 1985 levels by the year 2000 and 50% in the longer
term.22 Such consideration would enhance the current value of conservation and renewable energy
technologies.
Technology Risk. Some renewable technologies are relatively new, and utilities and PUCs are
reluctant to invest in technologies perceived as economically risky. The recent experience with
nuclear construction programs has made utilities and PUCs scrutinize future capacity plans to
determine if the power is needed. Given the need, utilities must have assurances that a given
technology can deliver the power reliably. Although renewable technologies have demonstrated
improved reliability, negative experiences with emerging renewable technologies (especially
intermittent technologies) during the 1970s and early 1980s have created unfavorable impressions
with many utility planners. As the increased reliability of intermittent technologies becomes more
apparent, however, utility planners obligated to incorporate environmental performance into resource
planning will evaluate more recent commercial expenence.
Technology risks can be shared among ratepayers, utilities, and taxpayers through federal
support of RD&D projects, utility joint ventures (e.g.. through EPRI), preferential tax treatment for
emerging renewable technologies, and liberal PUC treatment of emerging technology investments
through lenient prudency reviews. To the extent that technology risks are shared, in order to reduce
societal risks like global warming, individual utilities would be more willing to invest in renewable
energy projects. The potential environmental and other public benefits of expanded renewable
electric generation may justify policies that limit financial exposure to technology risks in order to
promote research and investment.
21 'Utilities to Cut Carbon Dioxide Emissions 20%.' Los Angeles Times, May 21, 1991.
22 Environmental Costs of Electricity, p 591
I-34
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The Clean Air Act Amendments of 1990
Two provisions of the Clean Air Act Amendments of 1990 will enhance the market for
renewable electric technologies. The most important influence in the long run will be the limit ("cap")
on aggregate S02 emissions from electric utilities, which will be administered through a system of
tradeable SO2 emission allowances. Utilities facing the emission cap will be forced to consider a wide
range of methods to produce electricity with less SO2 , and in a very real sense, the cap will
encourage utilities to adopt a pollution prevention stance toward producing electricity. Utilities could
view conservation programs, generation efficiency improvements, and renewable energy sources as
methods available to operate less expensively than installing expensive emission controls or
purchasing emission allowances.
Additional near-term renewable energy incentives will come from the pool of 300,000
allowances (tons of SO2) that has been earmarked for conservation and renewable energy options
between 1992 and 2000. Initial projections indicate that allowances could be worth between $200 and
S600 per ton of SO2 (this amounts to 0.04 to 0.12 cents per kWh, based on an SO2 emissions factor
of 2x10"6 tons per kWh). Depending on eventual market prices, this pool represents allowances that
may be worth up to S180 million to conservation programs or developers of renewable electric supply.
I -35
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CHAPTER II
RENEWABLE ELECTRIC OPPORTUNITIES
The prospects for expanded renewable electric generation depend primarily on the economics
of conversion, the extent to which environmental advantages are reflected in the market, and the
evolving regulatory and competitive framework that governs electricity supply decisions. This chapter
focuses on three issues: (1) the technical potential of renewable energy is far larger than its current
contribution, (2) the economics of renewable resource conversion are improving, and (3) the
regulatory and political climate is becoming more favorable for development of renewable energy.
This report suggests that if these issues evolve favorably for renewables, the incremental contribution
of renewable electricity could more than triple by 2000, and increase four-and-a-half times by 2010.1
THE RENEWABLE ENERGY RESOURCE BASE
The total potential renewable energy base is much larger than the total potential fossil fuel
resource base. Fossil fuels began as organic material that stored solar energy (and atmospheric
carbon) through photosynthesis millions of years ago. Only a fraction of the ancient biomass resource
(mostly plant material) was transformed into useful chemical energy. However, this fossil energy is
concentrated and, once extracted, is easily converted into useful energy forms such as liquid fuels
and electricity.
All renewable energy is derived from the sun.2 Biomass and hydropower are concentrated
and storable solar energy forms. Biomass is the solar energy stored in plant and animal matter
through photosynthesis and metabolic conversion. Hydroelectric power is solar energy stored when
evaporated water is deposited in higher elevations, which gravity converts to kinetic energy. Other
solar resources are more immediate, diffuse, and intermittent. Windpower is the result of uneven solar
absorption that creates moving air masses. Solar thermal and photovoltaic energy use direct and
indirect sunlight received during the day.
The amount of potentially useable energy from these renewable resources is quite large.
Much research has been devoted to estimating the size of fossil resource bases that could be
1 Based on incremental renewable generation in the EPA Enhanced Market scenario over the EPA Base Case
(see Ch III. Tables 111-2.4)
Geothermal energy, which is heat thai is stored in the earth and replenished through radioactive decay, is
technically not a renewable resource It is included in this report because the resource is so vast that it shares
many of the same properties as renewable energy sources
II - 1
-------
extracted and used under various technical and economic assumptions. Similar efforts for renewable
resources have only recently been initiated. Figure 11-1 shows a recent estimate of U.S. fossil and
renewable resource bases prepared for DOE.3 Of course, neither fossil nor renewable resource
bases are fully exploitable, due to technological constraints and economic considerations. In order to
make more meaningful comparisons, a distinction is made between the resource base (total
potential), accessible resources (feasible potential under current or nearly developed technology),
and energy reserves (economic potential under existing technology).
According to the DOE analysis, the U.S. renewable energy base is composed primarily of
geothermal, solar, and wind resources. The renewable energy resource base is 14 times the U.S.
fossil energy resource base, which is dominated by coal and shale oil. The picture reverses when
only energy reserves are considered. Under current market prices and conversion technologies, fossil
energy reserves are more economically exploited than most renewable energy forms. Reserves of
natural gas represent about 25% of the total gas resource base and coal reserves make up about
15% of the total coal resource base. In contrast, only 1% of the geothermal and 0.06% of the
photoconversion resources are currently economic to capture as renewable energy reserves
according to the DOE analysis.
The prospects for renewable energy are more optimistic, however, when accessible resources
are considered. Accessible resources are those that can be exploited with current technology or
technology that will be available in the near future. The accessible direct solar resource base is
eleven times larger than the accessible fossil fuel resource base; the biomass accessible resource
base is larger than the domestic oil accessible resource base. Taken together, the accessible
geothermal and wind resource base is over 70% of the entire domestic coal resource base.
ft must be noted that energy resource assessment is inherently inexact, and the definitional
and measurement problems are especialty severe for renewable energy forms. Thus, the figures are
useful for comparing rough estimates and pointing out the magnitude of untapped renewable
resource potential. While specific definitions of accessibility and "reserves" may vary from study to
study, most estimates suggest that cost remains the main barrier to renewable energy development,
not resource availability or technological feasibility. The extent to which renewable accessible
resources are nearly economic (i.e. could be counted as reserves) will determine the long run
potential for renewable energy supply.
3 See Characterization of U.S Energy Resources and Reserves, prepared by the Meridian Corporation for the
Deputy Assistant Secretary for Renewable Energy, u S. Department of Energy, 1989 The Meridian analysis
multiplies annual renewable energy quantities (flows) by 30 years in order to obtain a comparable figure with fossil
energy quantities (stocks)
II -2
-------
FIGURE 11-1
TOTAL & ACCESSIBLE RESOURCE BASE
4,000,000
Renewable*
Fossil
Total Resource Base: The combination of
undiscovered and identified, subeconomic
and economic concentrations of naturally
occunng solid, liquid, or gaseous materials in
or on the Earth's crust.
Source: Meridian, "Characterization of U S
Energy Resources and Reserves", 1989
TOTAL ACCESS BLE
RE NEW ABU RENEWABLE
TOTAL ACCESSIBLE
FOSM. FOSSl
ACCESSIBLE RESOURCE BASE & RESERVES
Renewable*
Fossil
ouu.uuu -
600,000 -
(0
•o
O 400,000 -
.
200,000 -
0-
A!
BBCBBBB:
ICESSIBL
x Hydropower
^Wlnd
Btomaaa
Solar
, Geothermal
£ RENEWABLE
Natural Ga*
/ Petroleum
/Coal
^ttj- Shale Oil
ACCESSIBLE FOSSL
RENEWASLE RESERVES FOSSIL RESERVES
Accessible Resource: That
subset of the total resource base
that can be captured, mined, or
extracted by current technology or
technology which will be available
in the very near future (3-5 years)
Source: Meridian; 1989
1
O
6,000
5,000 -
4,000 -
3,000 -
2,000 -
1,000 -
0
RESERVES
Renewable* Fossil
Hydropower
Wind
Blomaaa
Solar
Geothermal
Natural Ga»
Petroleum
Coal
Shale OH
RENEWABLE
RESERVES
FOSSH
RESERVES
•Renewable energy annual values are multiplied by 30 years
to arrive at a generally comparable figure with fossil fuels
Reserves: That subset of
the accessible resource
which is identified and can
be economically and legally
extracted to yield useful
energy or an energy
commodity.
Source: Meridian, 1989
II-3
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IMPROVEMENTS IN CONVERSION TECHNOLOGIES
One important reason that renewable energy does not contribute more to the U.S. electric
supply is that it often costs more per kWh than fossil fuel-fired generation. This economic
disadvantage could diminish (or perhaps even reverse) if the market price of fossil fuels reflected
environmental externalities. Other important factors also constrain the contribution of renewable
energy:
• First Cost - the tendency of the marketplace to prefer minimal initial costs for
investment decisions in decision making, which biases options such as renewables
that have little or no fuel cost and incur little, if any, escalation in costs over time;
• Risk - the lack of demonstrated performance of some renewable options makes their
initial use considerably more risky than conventional options;
• Production Levels -- the need for renewables to achieve a modest production level to
achieve economies of production; and,
• Information/Education -- some renewables have demonstrated major
cost/performance improvements dunng the 1980s, although this may not be widely
known.
Recent Market Experience
Technologies to capture and convert renewable energy have been improving rapidly. The
most mature technologies -- biomass combustors and hydraulic turbines -- are similar to fossil fuel
technologies in that they convert relatively concentrated and stored solar energy into electric power.
Accordingly, biomass and hydroelectricity currently contnbute far more electricity supply than other
renewable technologies. Geothermal technologies also exploit concentrated energy sources, but
historically have been too expensive to locate and extract, given the amount of thermal energy
geothermal resources could provide. However, the cost of exploiting geothermal energy will fall as
exploration, drilling, and conversion technologies continue to improve. The technologies for capturing
more diffuse intermittent solar energy sources, such as wind and sunlight, have only recently become
commercial for producing electric power. However, these technologies have improved dramatically in
the past decade, and analysts predict that efficiencies will continue to increase, bringing down
conversion costs.
Compared wrth renewable technology costs, conventional fossil fuel generating technology
costs have remained stable in recent years. Figure II-2 shows how cost reductions for fossil fuel-fired
steam capacity nearly leveled out by the 1970s. While improvements in fossil fuel generation will
continue to occur, especially for advanced natural gas generation, further cost reductions are more
-4
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FIGURE II - 2
HISTORICAL FOSSIL FUEL CAPACITY COSTS
$
JL
w
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rs.
CD
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1000
900
800
700
600
500
400
300
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l 1 1 1 1
1950 1955 I960 1965
Vintoge or Yeor o< Construdion
Source: Robert H. Williams and Eric D. Larson, "Expanding Roles for Gas
Turbines in Power Generation." in Johansson, et. al., eds, Electricity:
Efficient End-Use and New Generation Technologies, and Their Planning
Implications, (Lund University Press, 1989).
II-5
-------
likely to be incremental rather than dramatic.4 With a few exceptions, renewable electric technologies
are at earlier stages of technological development than fossil fuel competitors, and are more likely to
experience improvements that could significantly enhance their comparative economic
competitiveness over the next decades.
Renewable Technology Research and Development
The renewable electric industry is relatively new - particularly solar and wind -- compared to
the mature, established fossil fuel industry. Renewable energy received generous R&D funding
support during the late 1970s, but funding fell off abruptly in the early 1980s. As Figure II-3 shows,
R&D funding for renewable energy continued to decline steadily during the 1980s. Renewable energy
currently accounts for 5% of the federal research and development for energy supply and
conservation.5 Figure II-3 also shows that fossil energy R&D was also cut significantly in the early
1980s, but has since been restored to late 1970s levels.
Many renewable technologies continued to improve with limited federal R&D support during
the 1980s. These improvements occurred as a result of expanded private R&D efforts and increased
commercial experience, and as federal R&D conducted during the late 1970s translated into
commercial cost reductions. As discussed in subsequent chapters, renewable energy R&D efforts
continue along many technological pathways. Given the large number of pathways and technological
opportunities for cost reductions, there is a high probability that some technologies will achieve much
greater cost competitiveness with fossil fuels over the next decades.
Expanding International Markets for Renewable Technologies
Developed nations that commit to greenhouse gas reductions will provide additional markets
for renewable energy technologies. Taken together with the energy needs of developing nations,
renewable energy technology industries are poised for significant growth in the coming decades. This
growth could accelerate the cost reductions expected from U.S. demand for renewable electric
technologies. To the extent that expanded domestic market growth is stimulated by U.S.
environmental policies, the competitive stature of U.S. manufacturers and developers would be
4 In fact, the area of greatest recent cost improvement for fossil fuel technologies has been for pollution control
equipment, a market which was essentially created in the 1970s by the Clean Air Act. This demonstrates the ability
for technologies to improve in a short period of time given sufficient market stimulus.
5 See 'Energy Use and Emissions of Carbon Dioxide Federal Spending and Credit Programs and Tax
Policies," Congressional Budget Office, December 1990, Table 2.
II -6
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enhanced further. Extending domestic market gains to growing markets abroad could help reduce
the current U.S. trade deficit.
The growing economies of many populous developing nations have abundant renewable
energy resources. As these nations attempt to meet the growing expectations of their citizens to raise
Irving standards, they must decide on energy supply strategies. Many developing nations would
prefer to exploit indigenous renewable energy resources than import fossil fuels for meeting energy
needs, since such policies can serve as a buffer against oil price fluctuations and save scarce hard
currency. Although definitive estimates of worldwide sales of renewable energy technologies do not
exist, the current international market for renewable energy technology probably exceeds $2 billion
annually.6
These potential markets have stimulated the governments and industries in some developed
nations to finance renewable technology RD&D and export promotion programs. The U.S. leadership
in several areas of technology development eroded during the 1980s, and the U.S. was a net importer
of wind and solar electric energy systems in recent years.7 While U.S. federal renewable energy
RD&D expenditures were scaled back during the 1980s, other countries continued research support at
steady levels. As shown in Table 11-1, the United States was a leader in 1986 in terms of total dollars
spent on renewable R&D with a budget of $177 million, however, ft trailed other countries in the share
of total energy R&D budget allocated to renewables and renewable R&D spending per capita.
FAVORABLE POLITICAL CLIMATE FOR RENEWABLES
A broad array of local, state, national, and international concerns and actions are operating to
enhance the market potential of renewable electnc generation. Some of these concerns are
manifested in recent regulatory reform, while others are reflected in political debates. All of these
factors indirectly increase the economic destrabilrty of renewable energy options.
While it is difficult to predict the impact of political movements, they are likely to encourage
renewable energy development over the next decades Much of the progress made in environmental
regulation and rate regulation discussed in the previous chapter occurred as a result of public
6 See "Renewable Energy Federal Programs' by Fred J Sissine (Washington, D.C.: Congressional Research
Service. Issue Brief IB87140. April. 1990). p 12
7 See 'Renewable Energy. Federal Programs' p 13 Also, see Energy R&D: Changes in Federal Funding
Criteria and Industry Response (Washington DC, US. General Accounting Office, February, 1987).
II-8
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TABLE II - 1
GOVERNMENT R&D SPENDING ON RENEWABLES
SELECTED COUNTRIES, 1986
Country
Sweden
Switzerland
Netherlands
West Germany
Greece
Japan
United States
Italy
Denmark
Spain
United Kingdom
Renewable R&D
Spending
(million $)
17.3
10.2
17.0
65.9
9.7
99.2
177.2
29.5
2.6
19.4
16.6
Share of Energy
R&D Budget
(percent)
21.8
14.7
10.6
11.6
63.2
4.3
7.8
3.9
17.8
27.6
4.4
Spending
Per Capita
(dollars)
2.06
1.57
1.17
1.09
0.97
0.82
0.73
0.52
0.51
0.50
0.29
Source: 'Shifting to Renewable Energy by Cynthia Pollock Shea in State of the World 1988: A
Worldwatch Institute Report on Progress Toward a Sustainable Society.
II-9
-------
pressure to minimize environmental impacts of energy supply. The public concern over environmental
impact continues to promote renewable energy as an alternative to fossil fuels.
Public Environmental Concern
Support for renewable energy options has come from states and local communities concerned
about the broad environmental impacts of a variety of activities. Recent polls of U.S. voters have
shown consistently that citizens support and are willing to pay for additional environmental protection
or improvement. One recent poll indicated that 75% of those surveyed believe that the U.S. should
reduce energy demand through efficiency measures, and 59% favored accelerated development of
renewable energy sources. Of those surveyed, 73% said that they would be willing to pay more for
fossil fuels if the added cost was used to prevent serious consequences of global warming.8
State and local initiatives reflect the public concern over environmental damages, and a 'quiet
revolution* has emerged that addresses broader national issues at the state and local level. For
example, Vermont has banned CFCs in automobile air conditioners by the 1993 model year, and the
city of Irvine, California has enacted local ordinances prohibiting the manufacture, sale or distribution
of products utilizing ozone depleting substances. Connecticut has enacted legislation to ensure that
new buildings conform to strict energy efficiency codes, and Iowa has passed a bill to encourage
alternative energy production.9 Given the level of public support for environmental action, more state
and local initiatives promoting renewable energy are likely to emerge during the 1990s.
Oil Dependence
The recent Iraqi invasion of Kuwait and subsequent U.S. military response have revived
concern over oil dependence. Although oil provides only about 5% of electricity generation in the
U.S., some regions in the Northeast and South rely on oil for 20% to 40% of generation. The
economic cost of unreliable oil supplies could be high for electncity consumers in these regions.
Beyond the environmental effects of oil use, the cost of maintaining the Strategic Petroleum Reserve
and supporting military intervention suggest that the U S market price for oil remains below social
cost. Because most oil is consumed as transportation fuel. DOE supports research and development
8 See 'America at the Crossroads A National Energy Strategy Poll,' sponsored by The Alliance to Save Energy
and The Union of Concerned Scientists, January 1991
See Selected Summary of State Responses to Climate Change, report by the Bruce Company prepared for
the Climate Change Division of the Office of Policy. Planning, and Evaluation. U.S. EPA January, 1991.
II - 10
-------
into renewable fuels such as biomass-derived ethanol and methanol. This research could have
important spillover benefits for biomass generated electricity.
Greenhouse Gas Protocols
The Intergovernmental Panel on Climate Change (IPCC) sponsored by the United Nations
Environmental Program (UNEP) has begun the process of identifying opportunities for greenhouse
gas reductions in both developed and developing countries. The main emphasis is reducing fossil
fuel emissions .n the developed nations and stemming the potentially explosive emission growth in
developing countnes. Although the U.S. has not formally entered into agreements to reduce
greenhouse gases, other developed countries have declared their intentions to stabilize or reduce
emissions over the next decade and beyond. Table 11-2 shows the current positions of these nations
on CO2 emission targets. Developed countries that import most of their fossil fuel supplies, such as
the Scandinavian countries and Japan, have committed to CO2 reduction targets; developed nations
that currently exploit indigenous coal resources, such as the United Kingdom, Australia, and Germany,
have also committed to reducing CO2 emissions.
POLICIES TO INCREASE RENEWABLE ENERGY CONTRIBUTIONS
The political trends identified above and the regulatory reforms discussed in Chapter I
enhance the prospects for renewable electric generation. Further enhancements, such as more
widespread and stringent environmental valuation, new approaches for accommodating intermittent
generation, additional R&D support, federal and state tax policy, and aggressive promotional
programs could significantly increase the market penetration of renewable electric technologies in the
future.
Greater Environmental Valuation in Resource Planning and Operation
According to the range of estimates shown in Table 1-3 in Chapter I, the external cost of fossil
fuel electric generation may exceed the production cost of electricity. A few states have incorporated
external cost into the planning process, but at relatively modest levels. As more states adopt
environmental valuation, and incorporate higher damage estimates, renewable generation technology
will become more competitive, and its contribution could substantially increase. Policies that give
greater weight to environmental performance in bid evaluations, provide set-aside blocks of energy to
be met by renewables or conservation, or institute environmental adders (e.g. granting certain options
a percentage value increase in planning) could be as effective as explicit quantification of
environmental externalities.
11-11
-------
TABLE II - 2
POSITIONS ON CO2 EMISSION TARGETS
Stabilization, 1995
Stabilization, 2000
Stabilization at 10%
by 2000
Stabilization, 2005
3-5% reduction, 2000
20% reduction, 2005
25% reduction, 2005
Support targets for
developed countries;
weaker or no targets
tor LDCs
Oppose targets
Netherlands
Australia
Austria
EC Commission
Finland
Italy
Japan
Norway
Sweden
Switzerland
France
Canada
United Kingdom
Netherlands
Austria
Denmark
New Zealand
Germany
Brazil
China
India
Malta
Mexico
Saudi Arabia
USSR
Israel
Venezuela
Base Year
1989-90
1988
1990
1990
1990
1987
1988
1990
1988
1990
1989-90
1988
1990
1987
Source. Second World Climate Conference,
November 1990, Geneva, Switzerland
II -12
-------
Environmental valuation can also be applied to short run dispatch decisions. Environmental
impacts from one existing utility plant to another can differ significantly when generating electricity, but
pure economic dispatch does not take into account these costs. However, operation of some units
may be modified to attain existing environmental standards, which can affect the cost of generation.
At the other end, pure environmental dispatch would give priority to the lowest emitting units, but
would cost more. In between the two extremes of pure economic dispatch and pure environmental
dispatch, a lull social cost economic dispatch would take into account economic and environmental
values. A recent analysis of utility dispatch including social cost has shown that environmental
valuation could reduce SO2 emissions by 67%, NOX by 26%, and CO2 by 19% in a typical utility
system.10
Environmental Taxes and Penalties
Environmental taxes or penalties on fossil fuel or emissions have often been suggested as an
efficient market-based policy to 'internalize' the external costs associated with energy use. For
example, a recent Congressional study examined the impacts of fossil fuel penalties based on carbon
content of fuel as a policy to reduce CO2 emissions.11 Depending on the basis (e.g. fuel or
pollutant emissions) and the tax levels chosen, such policies could obviate the need for environmental
valuation in utility planning, since the costs of various supply options would reflect environmental
damages associated with them. If such policies are enacted, renewable electric generation could
increase substantially because its cost relative to fossil generation would decline.12
Regulation and Planning for Intermittent Generation
Three renewable electric technologies - photovoltaic, solar thermal, and wind -- depend on
intermittent renewable resources.13 The premium placed on overall system reliability limits the
interest of utilities in intermittent sources. Although most utility systems could accept larger portions
of intermittent generation than they currently handle, thinning reserve margins in many regions may
10 See 'Full Cost Economic Dispatch Recognizing Environmental Externalities in Electric Utility System
Operation' by Steven Bernow, et al presented at National Conference on Environmental Externalities, National
Association of Regulatory Utility Commissioners, October, 1990
11 Carbon Charges as a Response to Global Warming: the Effects of Taxing Fossil Fuels, Congressional
Budget Office, August, 1990
12 See Ch III Externalities Penalties Case
13 Hydroelectric is normally dispatchable, but seasonal water level variations or prolonged droughts limit
availability Although it is also an intermittent resource, utilities have gained much experience at adapting to
hydropower fluctuations
11-13
-------
force utilities to value firm* (reliable and dispatchable) capacity over technologies that may not deliver
power during peak load periods. From a utility planning perspective, intermittent resources may not
eliminate the need to build capacity to meet peak demands, reducing the value of intermittent
generation. This is manifested in the PURPA market as power purchase terms for intermittent
renewables based only on the avoided variable cost to the utility, i.e., intermittent renewables generally
do not receive payment for avoided capacity costs.
The process of utility planning or competitive procurement may not give enough "capacity
credit* to intermittent sources because of the narrow terms upon which individual projects are
evaluated, and in some cases because it does not give enough weight to the coincidence factors
(when power output from intermittent resources in some regions is highly correlated with utility peak
demand). Adapting utility planning or bidding procedures to give more value to intermittent resources,
when some capacity credit may be warranted, would increase the competitive status of these
technologies. The Renewable Electric Model results provide partial capacity credits for wind energy
where the data indicate that sufficient coincidence factors exist (see Ch. IX for details).
Another way to overcome intermittent resources is to develop hybrid technologies that utilize
storage or fossil fuel backup to firm' the resource.14 A good example of this strategy is the solar
thermal generating stations built by Luz in California, where natural gas backup fuel is used to provide
power during cloudy periods and to extend operation into early morning and late evening hours.
Likewise, fossil-fuel backup could firm wind or PV generation. The fossil energy contribution allowed
for QFs under PURPA is currently limited to 25%, however, the administration has recently expressed
support to raise the limit to 50%.1S Chapter X discusses the potential for hybrid technologies to
increase the energy value of intermittent renewable generation.
Additional Research. Development and Demonstration Support
As mentioned in Chapter I, renewable electnc technologies would benefit from expanded
RD&D support. A recent study conducted by the Department of Energy (DOE) and the Solar Energy
14 To the extent that the renewable technology allows less fossil capacity to be developed, the renewable
technology earns that capacity credit on its own In combination, fossil-renewable hybrids allow total costs to be
lowered in addition to earning firm capacity credits The capacity credits may be due to a combination of fossil and
renewable generating capacity
15 See National Energy Strategy: Powerful Ideas for America, First Edition 1991/1992, (Washington, D.C.
February 1991) p 125
II - 14
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Research Institute (SERI)16 estimated the cost reductions and market gains from an aggressive
RD&D program over the next 40 years. Table II-3 shows the DOE/SERI projections of the levelized
generation cost in the accelerated RD&D case, expressed as the percent of 'Business as Usual' costs
for the years 2000 and 2010. Additional RD&D reduces projected generation costs by between 10%
and 40% in most cases, with even greater reductions for most technologies after 2010.
A recent report by the National Research Council recommended that the DOE reallocate about
$300 million of its energy research budget from fusion and fossil fuel programs to renewable energy
and conservation technologies.17 The advisory panel stressed the need for long-term energy R&D
policy to take into account the potential climate change impact of research agendas, and argued that
providing greater support to renewable energy technologies would help shift energy production away
from fuels that emit greenhouse gases.
Cumulative Commercial Experience and Learning Curves
While difficult to predict or quantify, expanded commercialization of renewable energy
technologies will accelerate cost reductions. Economists refer to the cost reductions gained through
commercial production as "learning curve" impacts, where costs are a function of cumulative sales of a
product. The relationship between production cost and experience is often stronger and more
indicative of technology maturation than the reduction of cost through time. Whatever the causes,
evidence abounds suggesting that cumulative commercial experience can lead to significant cost
reductions.18
Since many renewable energy technologies serve a relatively small market, many of the gains
from manufacturing scale, standardization, and learning curve improvements for newly commercial
technologies lie in the future. Experience shows that the transition to a stable and mature market can
significantly reduce manufacturing or construction costs of energy supply technologies, while
improving efficiency and performance. As discussed in subsequent chapters, substantial cost
reductions have already occurred for some renewable electric technologies during the 1980s.
16 The Solar Energy Research Institute (SERI) recently changed its name to the National Renewable Energy
Laboratory (NREL) References in this document reflect the time period prior to the name change and use the
acronym SERI
17 See Confronting Climate Change: Strategies for Energy Research and Development (Washington, D.C.:
National Research Council, 1990).
1ft
For example, the average price of computer equipment, based on a ratio of real price per unit of
performance, declined by 87% between 1972 and 1985
II- 15
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Continuing technological improvement will expand markets for renewable electric generating systems,
and costs will continue to decline as renewable energy industries attract more investment.
The economics of learning curves suggest that rising market demand is a powerful force in
commercial technology improvement. Broad-based policies to encourage near-term market demand
for renewable electric technologies in the U.S. can stimulate cost reductions that will make renewables
more competitive. Growing international demand for renewable electric technologies will provide
further market stimulus for cost reductions, both for U.S. and foreign suppliers. For some products,
especially advanced electronics used in military applications, federal procurement has been the
driving force behind innovation and cost reductions, which later yielded benefits in the form of new
and better civilian products. While private utilities are the main market for electric generating
technologies, the federal government also owns generating capacity e.g., the Tennessee Valley
Authority and the Bonneville Power Administration. Thus, some opportunity exists for federal
procurement to nurture renewable electric learning curve economies. Overall, these cost reductions
associated with scale economies are a key element in enabling renewable electric generation to
increase its penetration in EPA's 'Enhanced Market' scenarios for 2000 and 2010 (see Chapter III).
Tax Policies to Promote Investments in Renewables
Some renewable technologies qualify for investment tax credits. These tax credits have
survived rather precariously from year to year in Congressional deliberations, and the current tax
credits are due to expire in December 1991. In recent years, 10% tax credits have been available for
solar thermal, photovoltaic, and geothermal investments. These credits could be extended to other
renewable technologies, such as windpower; credits could be increased beyond the current 10% rate;
and the program could be extended indefinitely in order to increase investor confidence in the early
planning stages of renewable energy projects. To be effective, developers must be able to depend on
the tax credits being available from the planning stage through construction, including the period in
which capital is raised and the facility is sited. Tax credits that are renewed on an annual basis are
often not reliable enough to justify investment commitments. Other tax-related proposals have
included changing the basts of the credit from capital investment to energy production, in order to
more effectively target renewable energy generation.
Energy Pricing and the 'Level Playing Field'
Many energy analysts contend that energy markets are biased toward fossil fuels and against
renewable energy. Aside from environmental externalities that remain unpriced in the market, they
point to direct government support that favors fossil fuel supply, such as R&D, as well as indirect
II- 17
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government subsidies through tax provisions. While such a bias may exist, no definitive measures of
the magnitude of such biases has emerged. Some studies have cited direct and indirect subsidies
worth tens of billions of dollars annually.19
A complete examination of direct and indirect subsidy for fossil energy is beyond the scope of
this study. Some government support of fossil energy clearly promotes its use, while other forms of
support, such as R&D into efficient conversion technologies, could help reduce fossil energy use. In
either case, concern for the environmental impact of expanded fossil fuel use could motivate
fundamental changes in direct support programs, tax policy, and R&D priorities that would make
renewable resources more competitive with fossil fuels.
19 See The Real Cost of Energy" by Harold M. Hubbard, Scientific American, Vol. 264. No. 4, April, 1991, p. 36,
and The Hidden Cost of Energy: How Taxpayers Subsidize Energy Development," by Richard Heede, et.al, for the
Center tor Renewable Resources, Washington DC, 1985.
II- 18
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CHAPTER III
THE EPA MARKET ASSESSMENT
In order to estimate the air pollution reduction potential of renewable generating technologies,
important features of the U.S. electricity markets and renewable resource bases must be taken into
account. Because renewable technology operating characteristics and availability differ across
regions, and because regional electric power systems differ with respect to capacity and fuels, some
renewable electric generating options could prevent more air pollution than others. These same
regional factors- affect the relative costs of renewable and fossil fuel generating options. The market
assessment analysis identifies those renewable electric power options that are most likely to reduce
CO2 and other emissions in the near term, and estimates the costs of substituting renewable energy
for fossil fuels in electric power generation.
CONSTRUCTION OF THE EPA RENEWABLE TECHNOLOGY PENETRATION SCENARIOS
In order to analyze the cost and air pollution prevention impact of renewable electric
technology, renewable technology penetration scenarios were constructed for the 12 regions shown
on Figure 111-1. Ten technologies are considered: biomass solid (primarily wood), municipal solid
waste, landfill and digester gas, geothermal, hydroelectric run of river, hydroelectric storage,
photovoltaic, solar thermal electric natural gas hybrid systems, solar thermal electric stand-alone
systems, and windpower. The scenarios extend to the year 2010. Many of the scenarios are based
on a recent study conducted by the Department of Energy (DOE) and the Solar Energy Research
Institute (SERI).1 Table 111-1 summarizes the aggregate generation and capacity for the two EPA
scenarios examined in the analysis, along with the three DOE/SERI projections.2 The EPA scenarios
bracket a wide range of possibilities, reflecting the uncertainty that exists regarding the technological
and market penetration prospects for renewable electric generation.
1 The Potential of Renewable Energy, Intertaboratory White Paper prepared for the Office of Policy, Planning,
and Analysis. U S Department of Energy (Golden, Colorado: Solar Energy Research Institute, March, 1990). The
Solar Energy Research Institute (SERI) recently changed its name tho the National Renewable Energy Laboratory
(NREL) References in this document reflect the time period prior to this name change and use the acronym SERI.
2 The 1990 figures are slightly different than those reported in Table 1-1. This table displays the initial capacity
and generation data used in the Renewable Electric Model (REM). Some small discrepancies occur because some
capacity and generation figures were imputed using various data sources. Sources differ because of various
survey sample years (1988 through 1990) as well as definitional and methodological differences.
111-1
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TABLE III - 1
RENEWABLE ELECTRIC SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&O
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
109,600
129,000
136,600
103,700
147,400
Generation
2000
(GWh)
485,800
549,300
585,300
454,200
668,000
Capacity
2010
(MW)
168,600
282,700
290,900
146,200
379,000
Generation
2010
(GWh)
691,800
1,050,100
1,144,500
616,000
1,393,100
1990: 84,000 371,325
DOE/SERI Scenarios
The recent DOE/SERI Intertaboratory report contains renewable energy projections to the year
2030 under one trend scenario and two policy cases. Since the DOE/SERI report provided many of
the assumptions and data used in constructing the EPA renewable electric scenarios, the DOE/SERI
scenarios are briefly described here:
• The Business as Usual (BAU) scenario is based on current market trends.
Renewable electric generation grows at an annual average growth rate of 3.2%
between 1988 and 2010. Photovoltaic, solar thermal, and windpower are projected to
account for the most growth under this scenario.
The Intensified RD&D scenano reflects the impact of an increased program of federal
research, development, and demonstration (RD&D) support over the next several
decades. Renewable electric generation grows at an annual average growth rate of
5.3% between 1988 and 2010. All technologies respond to additional RD&D, but gains
are especially large for geothermal, photovoltaic, solar thermal, and windpower.
-3
-------
• The National Premiums scenario is based on giving renewable electric generation a
market premium of 2 C/kWh over fossil fuel-fired generation. Renewable electric
generation grows by 5.3% annually between 1988 and 2010 (as in the RD&D scenario)
but with slightly higher contributions by hydropower, biomass, and windpower than in
the RD&D policy case.
For some technologies, the EPA scenarios are identical to one of the DOE/SERI projections. For
those that differ, the DOE/SERI market projections provide a useful point of comparison to the EPA
scenanos. Because the DOE/SERI study did not report regional cost and specific technology data in
many cases, the pollution prevention and cost implications of the DOE/SERI scenarios are not
examined in this report.
EPA Scenarios
EPA constructed a trend scenario and a policy case scenario to the year 2010. The basic
assumptions underlying the renewable energy contributions are outlined in the individual technology
chapters that follow, and Appendix A provides detailed scenario descriptions.
Base Case. Using information from the DOE/SERI report and other sources, EPA constructed a Base
Case to reflect current trends. The EPA Base Case projects that renewable electric generation will
grow at an annual average growth rate of 2.6% between 1990 and 2010, slightly less than the
DOE/SERI BAU projections. The EPA Base Case is identical to the DOE/SERI BAU scenario for
geothermal, photovoltaic and solar thermal electric, but slightly below the BAU scenario for biomass,
hydroelectric, and wind. The EPA base case projects that annual renewable generation will increase
by about 245 billion kWh between 1990 and 2010. This is somewhat higher than a recent Energy
Information Administration (EIA) projection for renewable generation, which estimates that renewable
generation will increase by 200 billion kWh over the same time period.3
Enhanced Market Scenario. The EPA Enhanced Market scenario represents the near term potential
for renewable electric generation under both targeted and broad promotion policies, including
increased RD&D, environmental penalties for fossil fuel-fired generation, tax incentives, or other
targeted state or federal support. In some ways it resembles a combination of the DOE/SERI RD&D
and National Pnonties scenanos; consequently, the Enhanced Market scenario projects higher total
renewable electric generation than either of the DOE/SERI policy cases. In the aggregate, the EPA
3 Energy Information Administration, Annual Energy Outlook 1991, Table 6, p.31.
Ill-4
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Enhanced Market scenario projects that renewable electric generation will increase by over 1,020
billion kWh between 1990 and 2010.
The EPA Enhanced Market scenario is derived differently for each technology, giving extensive
consideration to mechanisms that would enhance electricity markets and stimulate the specific
renewable electric technologies in particular regions. Some technology penetration scenarios are
explicitly constructed from assumptions regarding future costs and renewable resource availability.
Other penetration scenarios are based on previously published analyses. Cost reductions are
assumed to be the product of increased private and public RD&D as well as expanded market activity,
including additional project development, consumer awareness, and other issues, that realize
manufacturing scale economies and learning curve impacts. These market responses are consistent
with an increased emphasis on environmental impacts of electric generating technologies, either
through state resource planning methods (bidding criteria, set-aside capacity blocks for renewable
energy sources, etc.) or broader federal policy options such as fossil fuel price penalties.
EPA MODEL DESCRIPTION
EPA constructed a model that accounts for the impacts of increased renewable electric
supplies. The Renewable Electric Model (REM) evaluates the emission and cost impacts of different
scenarios of technology penetration in the 12 regions shown on Figure 111-1. The time horizon for the
evaluation extends to 2010. The model accounts for the fact that both electricity markets and
renewable resource bases vary significantly across three dimensions:
• Region (12 regions of the U.S.)
Season (winter, summer and spring/fall)
• Time of day (peak and off-peak)
The fossil fuel mix and generating costs of electric utility systems are depicted in these
dimensions in order to estimate the utility resources that renewable electric options will displace.
Estimates of avoided (fossil fuel) variable costs, capital costs, and emissions are based on the plants
that otherwise would be dispatched to meet seasonal and daily loads in the absence of renewable
generation.4 The model incorporates judgments concerning the marginal (highest cost) fossil fuel-
4 In this report, "avoided" emissions and costs always refer to the fossil fuel-fired generation displaced by
renewables.
Ill-5
-------
fired plants in the utility dispatch decision for each load segment, as these would be the most likely to
be 'backed down* to accommodate additional renewable generation.5
The model estimates avoided capacity costs by identifying the season and time of day that the
annual system peak occurs in each region, the costs of incremental capacity (e.g. coal steam plants,
natural gas combined-cycle plants), and the likelihood that renewable generating technologies can be
relied upon to provide power at peak periods. Avoided variable cost plus avoided capital cost equal
the total avoided costs of conventional alternative supply.
The model further calculates the levelized cost of renewable generation, which can be
compared directly with avoided utility costs to give the net cost of renewable electric generation.
Emission abatement costs can be calculated on a per-ton removed basis by combining the net costs
with the avoided emissions. In this way, the most cost effective renewable energy pollution prevention
strategies can be identified.
The REM approach represents an analytical compromise between (1) using a regional
electricity dispatch and investment optimization (production simulation) model to estimate emission
reductions, and (2) applying simple national average emission factors to aggregate renewable market
projections. The former approach would represent a significant increase in analytical detail for modest
and potentially misleading gains in accuracy, since the renewable electric projections are subject to
more uncertainty than the capacity and operating assumptions that underlie utility optimization
models.6 The latter approach may not adequately capture some of the important characteristics of
renewable and fossil fuel generation, such as regional, seasonal, and time of day variation. The
compromise approach incorporates many of the important characteristics of renewable electric
generation and regional electricity markets. By captunng these important regional and temporal
variations, the REM can produce a fairty refined national profile of pollution prevention through
renewable electric generation.
5 This data was assembled by looking at the existing generating resources, fuel costs, and demand
characteristics in each region. The generation data were available through DOE/EIA publications and data tapes;
demand characteristics were based on data used in performing detailed simulations of utility system dispatching for
particular utility systems within each of the regions. The simulation model that this detailed data had been prepared
for was the Integrated Planning Model (IPM) developed by ICF Resources. Fuel costs were based on ElA's
escalated 1990 forecast
6 However, as discussed below, such an approach could yield more robust conclusions regarding the impact
of large increases in renewable electric technologies.
Ill-6
-------
INTERPRETATION OF MODEL RESULTS
The REM evaluates the avoided cost and emission impacts of assumed renewable electric
technology penetration scenarios. It does not, however, forecast renewable technology penetration in
electricity markets. Projections of individual renewable electric technology contribution to electric
supply and the future costs of renewable generating options must be derived independently, and such
projections involve a great deal of uncertainty.
Since both the future costs of renewable electric technologies and the amount of generation
projected are input assumptions in the REM, the model can evaluate scenarios that feature renewable
electric generation growth despite renewable costs that are generally higher than fossil generating
costs. The realism of such scenarios depends on the market and non-market factors assumed to
contribute to increased renewable energy use, as described in previous chapters.
Avoided Costs
The fossil fuel generating costs and emissions avoided by increased renewable generation
can differ among renewable technologies in the same region (on a per-kilowatthour basis). This
occurs because generation from different renewable technologies will displace different fossil
generating units during the day and throughout the year. Avoided fuel and operating costs depend
on the annual generating profile of a renewable technology. Utility capacity costs are avoided only to
the extent that renewable technologies provide reliable peak power.7 Thus, the value of dispatchable
renewable generation (as measured by avoided costs) will typically be higher than the value of
intermittent generation.
Because the REM estimates the avoided emissions and costs through a set of linear
coefficients that represent the marginal fuels displaced by renewable generation, the model becomes
progressively less accurate when evaluating large increases in renewable generation; coefficients are
based on relatively small increments. For example, the model implicitly assumes that (firm) renewable
generation displaces new capacity builds, and thus avoids significant capital costs. If aggressive
policies increase the contribution of renewable generation to the point of displacing significant
generation from existing plants (which could occur if expanded DSM programs curb demand growth)
The model assumes different 'capacity credits' for renewable generating technologies. For example, one
megawatt of biomass electric generation can fully displace one megawatt of conventional fossil capacity, and is
given a capacity credit equal to one On the other hand, the capacity credit for intermittent technologies such as
windpower is calculated as the fraction of each megawatt of windpower capacity that utilities could count on to
displace conventional power sources during peak demand hours. These are estimated separately for each
intermittent renewable based on regional resource availability during the peak utility season.
Ill-7
-------
then the avoided fossil fuel generation costs would be only the fuel and operating costs of existing
fossil units. The REM estimate would overstate avoided cost in this case. (However, emission
reductions may be underestimated to the extent that more coal-fired generation could be displaced
compared to the fuel mix displaced by more modest increments of renewable generation.) A more
detailed model of the electric generation sector would be required to analyze large changes.
The aggregate Base Case technology scenario represents a fairly modest fraction of overall
projected load growth, about 20% of EIA projections between 1990 and 2010. Under the Base Case,
therefore, the estimates of avoided emissions and costs are probably fairly accurate. However, the
EPA Enhanced Market renewable generation represents over 75% of the projected growth in electricity
demand through 2010. Given the limitations of the REM and the inherent uncertainty regarding
demand projections, the avoided costs of the Enhanced Market scenario might be regarded as an
upper bound, since this level of renewable penetration would likely displace only the variable costs
(fuel and operation & maintenance) of fossil fuel generation in some regions. On the other hand, the
intermittent renewables (solar and wind) are not assumed to fully displace conventional capacity,
limiting the possible bias in comparing renewable and fossil (avoided) costs.
Emissions
Air pollution prevented from three biomass electric technologies (wood and wood waste
combustion, MSW. and landfill gas) and solar thermal hybrid (natural gas backup) are computed on a
net basis. Depending on the relative emission rates of biomass technologies and displaced
conventional generation, therefore, some technologies will produce net emissions of NOX, SO2, CO,
and particulates. These are reported as negative pollution prevented. CO2 emissions from biomass
sources are assumed to be zero, which implies that fuelstocks are either grown on a sustainable basis
or that organic waste would eventually oxidize to CO2.
Avoided SO2 emissions are based on 1987 average regional emission rates for oil and coal
plants, and NOX emission rates are based on typical existing coal, oil, and natural gas capacity.
These assumptions are likely to overstate the SO2 and NOX reduction potential, since average
emission rates will fall (especially in the eastern U.S.) when the Clean Air Act Amendments of 1990 are
fully implemented.8 Moreover, to the extent that the emission cap of the Clean Air Act represents a
8 While average emission rates will fall, it remains unclear which coal plants will operate at the margin. It is
possible that historically high SO2 emitters will install scrubbers and operate at maximum levels in order to earn
allowances, and that historically "clean" plants would also operate in the same way. Thus, an "average" plant by
1987 standards could still be dispatched at the margin after 2000, and thus be displaced by renewable electric
generation
III-8
-------
binding constraint on national SO2 loadings, renewable electric generation will not actually reduce SO2
emissions at this rate. Instead, these figures could indicate the magnitude of emission allowances
created (freed for purchase by other emitters) through increased renewable generation. As such, they
represent an upper bound on either pollution prevented or, multiplied by the eventual market price of
SO2 allowances, the value of renewable generation in the allowance market. Allowances are
estimated to cost between $300 and $1000 per short ton of SO2 emitted, depending on market
demand.9
In addition to the CO2 emission results, a composite "CO2 equivalent" measure is also
reported. This measure is based on the global warming potential for greenhouse gases, integrated
over a 100 year time horizon.10 Carbon dioxide has a value of one, while other greenhouse gases
are weighted by the relative global warming potential as follows: methane, 21; carbon monoxide, 3;
and nitrogen oxides, 40. Thus, to the extent that greenhouse gases other than CO2 are reduced, the
CO2 equivalent measure will be larger than the CO2 emission figure.
Because the cost of greenhouse gas abatement has been the focus of considerable recent
attention, the model presents a dollar per metric ton removed calculation for CO2 and CO2
equivalent.11 Such abatement cost figures should be viewed with caution: to the extent that
renewable energy would reduce many fossil-fuel emissions simultaneously, attributing the entire cost
differential to one pollutant overstates the (unit) pollution prevention costs or savings. In addition, the
pollution prevention benefits or costs of technologies that displace some fossil fuel emissions and
create others will not be adequately expressed in single-emission abatement cost measures. A
weighting scheme such as CO2 equivalent gives a more complete picture, but only for the global
warming potential of the greenhouse gases. An ideal system would be economic valuation, that is,
weighting each unit of emission reduction by the dollar value of avoided damage. The total value
(summing across emission types) would provide a measure of the gross economic benefit from
reduced emissions. When divided by annual costs, such a measure would be a standard benefit/cost
ratio that would represent a net gain to society when its value exceeded one. However, the externality
9 However, the value of the emission offsets would not be independent of the amount of renewable electric
supply, since the price of SO2 offsets would be driven down under high penetration scenarios. Therefore,
estimates of the value of S02 offsets produced are subject to more uncertainty as higher renewable penetration is
assumed
10 The derivation of this weighting scheme can be found in Scientific Assessment of Climate Change report
prepared by the Intergovernmental Panel on Climate Change, June, 1990, Chapter 2.
11 This is calculated by dividing the difference between annual renewable cost and avoided fossil cost by the
annual tons displaced by renewable electric generation. Thus, if renewable generation costs $50 million per year,
avoided costs are $40 million per year, and CO2 is reduced by two million metric tons annually, then the abatement
cost would be $5/ton, or ($50 - $40)/2
III-9
-------
cost estimates for each pollutant discussed in Chapter I showed wide variation in absolute terms,
limiting the accuracy of direct benefit/cost valuation.
On the other hand, these same externality estimates suggest that the relative environmental
damages associated with coal-fired generation are larger than those incurred with oil or gas-fired
generation, as Figure 111-2 displays. This implies that CO2 emissions could provide a useful proxy
measure for the damages associated with a variety of pollutants arising from fossil fuel use. In other
words, the external costs of fossil fuel generation appear to be correlated with the carbon content of
fuel.
AIR POLLUTION PREVENTION ESTIMATES
The total air pollution prevented in the EPA scenarios is primarily a function of the overall level
of renewable generation assumed. However, air pollution reduction also depends on the mix of
technologies assumed in each scenario, and the geographic distribution of capacity additions.
Base Case Generation and Pollution Prevented
Tables 111-2 and 111-3 display Base Case results for renewable electric generation, costs, and air
pollution prevented between 1990 and 2010.12 In the Base Case, annual renewable generation
increases by about 245,000 gigawatthours (GWh) between 1990 and 2010. Combustion of solid
biomass fuels (wood, wood and agricultural wastes) account for 31 % of the increased renewable
generation, contributing an additional 77,000 GWh annually. Taken together, the three biomass
technologies (solid, MSW, and gas) account for 45% of the increased renewable generation. Annual
windpower generation grows by 46,000 GWh between 1990 and 2010, accounting for 19% of the
increased renewable generation. Hydropower. facing increased environmental constraints, grows by
only 14,000 GWh annually between 1990 and 2010.
Not surprisingly, the amount of air pollution prevented by each technology is roughly
proportional to the amount of total generation assumed. Because biomass-gas is assumed to prevent
emission of CH4 at the rate of combustion (i.e. the methane would eventually escape to the
atmosphere) it is the only renewable electric technology that eliminates methane in large quantities.
As discussed above, SO2 emission reductions must be viewed with caution: under the Clean Air Act
12 Although treated separately in the model, run-of-river and storage hydropower plants are combined for
reporting purposes, as are solar thermal (stand-alone) and solar thermal-natural gas (hybrid) systems.
Ill - 10
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cap, but would be translated into financial gains in the form of allowances.
The 600,000 metric ton decrease in annual NOX emissions by 2010 is about 33% of the 2
million (short) ton NOX reduction required by the Clean Air Act Amendments by 2001. The 204 million
metric ton reduction in CO2 emissions represents about 10% of current CO2 emissions from U.S.
electric generation, and about 6% of the EIA projection for the year 2010 (shown in Figure I-4 in
Chapter I). These emission results also show the tradeoffs encountered in increasing biomass
generation in terms of additional CO, and paniculate matter (PM): while net NOX, SO2, CO2 and CH4
emissions would decline, other environmental damage could occur. Nevertheless, the net increase in
PM and CO are very small compared to current emission levels: the 244,000 metric ton increase in
PM represents 4% of 1988 emissions (from all sources), while the 125,000 metric ton increase in CO is
only 0.2% of 1988 emissions.
Enhanced Market Generation and Air Pollution Prevented
The combination of policies assumed in the Enhanced Market scenario would increase
generation from all renewable technologies. Tables III-4 and III-5 display the Enhanced Market results
for renewable electric generation, costs, and air pollution prevented between 1990 and 2010. The
incremental renewable electric generation in the Enhanced Market scenario is 4.2 times the increased
renewable generation in the Base Case by 2010. Solid biomass combustion accounts for 34% of the
incremental generation between 1990 and 2010; generation is 4.5 times higher than Base Case levels
in 2010. Photovoltaics provide 19% of the increase in annual generation between 1990 and 2010,
while windpower and geothermal electric provide 14% and 13% of the incremental generation,
respectively.
Because of the regional technology mix assumed in the Enhanced Market scenario, the
increase in air pollution prevention is not always proportional to the incremental renewable generation.
The implicit SO2 reduction by 2010 in the Enhanced Market scenario is 4.7 times the Base Case
reduction; NOX reduction is 5.0 times the Base Case reduction; the CH4 reduction is 1.3 times the
Base Case, and the CO2 reduction is 4.3 times the Base Case reduction. Compared to the Base
Case, incremental renewable generation in the Enhanced Market scenario has 3.5 times the CO
emissions, and 1.2 times the PM emissions.
The implicit reduction in annual SO2 emissions in the Enhanced Market scenarios - as much
as 3.9 million metric tons -- could conceivably drive aggregate SO2 emissions below the mandated
cap (which would imply that the allowance price would be zero). The 2.4 million metric tons of NOX
III -14
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emissions avoided annually would exceed the reduction requirements of the Clean Air Act
Amendments by about 50%. Overall, the 670 million metric tons of CO2 emissions avoided annually
by 2010 in the Enhanced Market scenario are roughly 30% of the current level of CO2 emissions from
electricity generation, and would represent a 20% reduction from projected 2010 CO2 levels according
to the EIA forecast. In this scenario, renewables would cut the projected CO2 emission increase by
roughly 45%.
Additional context is provided by comparing EPA estimates of avoided emissions to projected
levels of energy-related emissions in the National Energy Strategy (NES).13 The NES projects
energy production and consumption and energy-related emissions for a Current Policies Base Case
(which does not include the Clean Air Act Amendments of 1990) and a Strategy Scenario. Avoided
emissions in 2010 in the EPA Enhanced Market scenario (compared to those in the EPA Base Case)
represent 9% of NOX, 10% of CO2, and 14% of SO2 emissions from all energy sources projected for
2010 in the NES Current Policies Base Case.14 The emissions avoided in the EPA Enhanced Market
scenario also represent a substantial portion of the emission reductions projected in the NES Strategy
Scenario (31%, 49%, and 74% of projected reductions in SO2, NOX, and CO2, respectively).15
Air Pollution Prevention Rates
By taking into account how renewable electric generation would affect utility system operation
in various regions, the REM can calculate specific air pollution prevention coefficients for each
technology.16 Table III-6 shows the average U.S. emission reduction rates per unit of renewable
electric generation for the EPA Base Case and Enhanced Market scenario, calculated by dividing the
total annual reductions of each pollutant by the incremental renewable generation. Since these
13 Technical Annex 2. Integrated Analysis Supporting the National Energy Strategy: Methodology, Assumptions
and Results, U S Department of Energy, First Edition 1991/1992 Tables 2-2 and 3-2.
14 EPA estimates can be compared to the NES Base Case because neither includes the Clean Air Act
Amendments of 1990, which substantially lower allowable SO2 emissions. Given the current system of tradeable
SO2 emission permits, however, these reductions would probably not occur. Rather, allowances would be created
that could then be sold to S02 emitters
1 This points out that the EPA Enhanced Market scenario represents a more agressive estimate of renewable
energy penetration than envisioned in the NES Strategy Scenario as a result of greater emphasis on pollution
prevention and on renewable electric resource and technology potential rather than cost effectiveness
16 The emission calculations do not take into account all aspects of utility system operation. For example, large
penetration of intermittent renewable generation could increase a utility's need for spinning reserves (units operating
at full or partial capacity but unconnected to load) An increase in spinning reserves could partially offset the
pollution reductions from additional renewable generation
III - 17
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numbers remain fairly stable between scenarios, they could be applied to other renewable electric
projections to estimate emission impacts.
These air pollution prevention rates indicate that, at the margin (and based on regional,
seasonal, and time-of-day attributes), additional windpower generation would prevent more CO2, NOX,
and participates than other renewable technologies, while geothermal and solar thermal would be less
effective at preventing air pollution than other technologies. Because biomass solid combustion
mainly occurs in regions where high-sulfur coal has been traditionally used as utility fuel, wood-fired
generation would be most effective at reducing SO2 (or generating emission allowances). Solar
thermal and geothermal electric generation, on the other hand, would tend to displace much less SO2
because of their regional distribution.
RENEWABLE AND FOSSIL GENERATION COSTS
The cost comparisons generally indicate the growing competitiveness of renewable electric
generating technologies compared with fossil fuel alternatives. However, a great deal of cost variation
exists among renewable technologies, and the geographic distribution and operating characteristics
(especially intermittency) of renewable technologies has a strong impact on the avoided costs.
Base Case Generation Costs
Table 111-2 shows the electric generation costs under current cost trends (Base Case). Under
these assumptions, the average renewable generating cost will be 2.4 0/kWh higher than fossil fueled
generation in 2000, a difference that will narrow to 0.3 c/kWh by 2010.17 Landfill gas and
geothermal electric technologies are less expensive than fossil fuel alternatives by 2000, while solar
thermal electric and hydropower technologies are also cost-effective by 2010 (as explained in Chapter
IV. MSW generation costs are assumed to be equal to avoided fossil costs). Biomass solid
combustion (wood and wood waste), photovoltaics, and wind are not projected to become broadly
competitive on a market price basis by 2010. However, these national averages mask the regional
results that indicate that biomass solid combustion and windpower will be less expensive than fossil
fuel generation in some regions.
One of the key factors in the competitiveness of renewable generation is the cost of
conventional supplies displaced. Avoided costs are a function of regional utility systems (generation
1 This represents a weighted average cost of all technologies in all regions, using the Base Case generation
projections as weights
III -19
-------
mix and fuel prices) and the operating characteristics of renewable energy sources, especially during
peak load periods when renewable generation could reduce the need for building additional fossil
capacity. For example, because intermittent windpower would displace little fossil fuel-fired capacity,
the cost of avoided fossil generation is based primarily on avoided variable costs and is valued at only
3.0 c/kWh in the year 2000. ™ In contrast, firm' renewable capacity such as biomass solid
combustion, which receives full capacity credit, has an avoided cost of 5.0 C/kWh. Solar thermal
electric hybrid generation (which is firm and operates exclusively during expensive peak utility demand
periods) achieves an avoided cost of 7.1 e/kWh. Chapter X examines ways in which intermittent
renewables such as PV and wind can earn capacity credit by using natural gas combustion turbine
backup systems.
Enhanced Market Generation Costs
As shown in Table III-4, average renewable generating costs are only 2.0 C/kWh higher than
fossil fuel generation in 2000, and are equal to fossil generating costs by 2010 in the Enhanced
Market scenario. Most renewable electric technologies would cost less under the Enhanced Market
assumptions, but average avoided costs are also lower as a result of additional renewable generation
in low avoided cost regions. The Enhanced Market scenario features large contributions from
biomass electric, photovoltaic, and windpower - technologies that would continue to cost slightly
more than the conventional generation they displace when valued at market prices. This highlights
the assumed rationale behind the Enhanced Market scenario: renewable technology potential would
be realized because of environmental advantages not necessarily reflected in market prices.
'Backstop' Technology Costs
A 'backstop technology" is a long-run concept of limitless (at least in relevant ranges of
demand) energy supply that is not subject to increasing costs over time due to progressive scarcity.
Since the EPA technology assessment extends for only 20 years, the analysis does not specifically
identify or estimate the costs of a single backstop technology. All of the renewable resources
considered here have additional expansion potential (except landfill methane, hydropower, and to
some extent MSW). PV is often mentioned as a backstop technology because PV uses ubiquitous
sunlight, is manufactured from abundant materials, and could be widely deployed. Likewise, hot dry
18 In the REM, windpower is given a capacity credit equal to: 1/2 of the regional capacity factor in 2000; and 2/3
of the regional capacity factor in 2010 (capacity factors rise between 2000 and 2010). Also, avoided costs for
windpower are lower than for other technologies because some windpower is generated during the night when
utility variable costs are low Windpower may have higher avoided costs in areas with relatively high levels of
hydropower capacity, where windpower intermittency is less of an obstacle.
Ill - 20
-------
rock or magma geothermal technologies could theoretically provide immense amounts of useful
energy, and the exploitation of wind resources remains far below estimates of technological feasibility.
However, many of these energy forms face technological constraints, such as intermittence, and may
have significant land-use impacts if universally deployed.
For these reasons, no single renewable technology is likely to provide pollution-free "backstop"
electricity generation over the next two decades. Instead, a portfolio of renewable electric generation
resources is likely to emerge if the U.S. undertakes significant shifts in energy production patterns in
order to minimize environmental impacts. By the year 2010, generation costs in the Enhanced Market
scenario range from 3.6 C/kWh (windpower), 3.7 C/kWh (biomass gas), and 4.0 c/kWh (geothermal) to
6.4 c/kWh (biomass solid combustion and photovoltaics). Since wind, geothermal, biomass solid
combustion, and photovoltaics all have significant expansion potential beyond the levels in this report,
backstop costs below 7 C/kWh could be expected if the market evolves in the direction of the EPA
Enhanced Market scenario. Both biomass and PV are relatively free of geographic and resource
constraints, compared with (hydrothermal and geopressured brine) geothermal, wind, and landfill gas,
and these two technologies could serve as "backstop" technologies for most regions. If technical
progress is limited to Base Case assumptions, then wind, landfill gas, and geothermal would still be
the lowest cost technologies - between 4.1 c/kWh and 4.4 c/kWh - while biomass solid combustion
would cost 7.0 c/kWh and PV generation would cost 11.5 c/kWh. If biomass and PV are considered
as backstop technologies in this scenario, backstop costs would be between 7 C/kWh and 12 C/kWh
in the year 2010.
ENVIRONMENTAL COSTS
The generation cost estimates discussed above are based on market prices for renewable and
conventional technologies. The relationship between air pollution prevention and relative generation
costs is further examined in two ways: constructing "air pollution abatement cost curves" for
renewable energy options, and estimating the impacts of environmental penalties on fossil fuel
generation.
Air Pollution Prevention Costs
Some of the air pollution prevented by renewable electric generation is obtained at a profit,
while others would add cost to electric supply. Tables III-2 and III-4 report the cost per ton C02
removed, and Figures III-3 and III-4 show these costs as a function of CO2 emissions avoided for each
scenario in 2000 and 2010. The figures rank technologies by ascending costs, and are analogous to
abatement cost curves familiar in pollution control analysis.
Ill - 21
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The abatement cost curves for CO2 show that Base Case conditions limit the cost-effective air
pollution prevention potential for renewable electric generation. As seen in Figure 111-3, CO2 reduction
costs quickly rise above $50/ton beyond 50,000 metric tons removed annually by 2000 in the Base
Case. By the year 2010, C02 abatement occurs at negative cost (renewable electric technologies that
eliminate CO2 cost less than conventional generation) for the first 50,000 tons removed, but costs
quickly rise beyond 100,000 tons per year prevented. The Enhanced Market scenario in 2000 shows
that nearly 250,000 metric tons of CO2 per year could be displaced by renewables at a cost of less
than $50 per ton, while another 600,000 metric tons of CO2 could be eliminated in 2010 for less than
$20 per ton.
These summary figures highlight a key finding of this report: under the Enhanced Market
assumptions, renewable electric generation can prevent significant amounts of air pollution at relatively
low cost.19 Market prices for most renewable electric generation technologies are unlikely to fall
significantly below fossil fuel-fired generation costs over the next two decades. However, renewables
could become broadly competitive during that period. If the environmental advantages of renewable
energy over fossil fuel generation were taken into account, then renewable energy would become a
cost-effective source of electricity supply.
Externalities Penalty Cases
If the environmental costs (externalities) of fossil fuel-fired electric generation were reflected in
market prices, the market cost of fossil fuel generation would rise relative to renewable electric
generation. This effect is demonstrated by applying environmental penalties to the price of fossil fuel
generation displaced by renewable electric options in the Base Case (i.e. increase avoided fossil fuel
costs). Penalties applied in proportion to the carbon content of fossil fuels could approximate external
costs from a variety of pollutants. Three scenanos were examined:
• A penalty set at $50 per metnc ton of carbon ($14/ton C02), which represents a low
estimate on fossil fuel externalities;
• A penalty of $100 per metric ton of carbon ($27/ton CO2) is close to the median
estimate of C02 emission damages cited in Chapter I (shown on Figure U7); and
19 As discussed before, at higher ranges of renewable penetration and emission reduction, avoided costs could
fall to variable fossil costs, which would increase abatement costs more steeply than shown in these figures.
Ill - 24
-------
A penalty of $250 per metric ton of carbon ($68/ton CO2) is near to the total externality
costs of fossil fuel generation cited in the Pace University and Hohmeyer studies.20
Table 111-7 shows the impact of these environmental penalties on the relative costs of renewable and
fossil fuel electric generation. The $50Aon penalty would add an average of 1.1 c/kWh to the cost of
fossil fuel generation displaced by renewables in 2000, and 1.2 0/kWh in 2010. Except for
photovoltaics, every renewable electric technology costs less than fossil fuel generation that includes a
$50/ton carbon penalty in 2010. This comparison does not rely on an optimistic forecast of renewable
costs; the result is obtained using the Base Case cost assumptions. The $100/ton penalty would add
an average of 2.3 c/kWh to fossil fuel generation in 2000, making fossil fuel-fired electric power cost
the same as renewable generation. The $250/ton charge would more than double the cost of fossil-
fuel electric generation, making all renewable energy sources except photovoltaic less expensive than
fossil fuel generation.
The impacts of fossil fuel environmental penalties on the avoided costs of each technology is
proportional to the average C02 emissions avoided (i.e. the pollution prevention rate discussed
above).21 Therefore, the $50/ton carbon charge adds 1.3 c/kWh to the avoided cost of windpower
and hydropower, while the same penalty would add only 0.8 c/kWh (in 2000) and 0.9 c/kWh (in 2010)
to the avoided cost of geothermal. Because renewable electric generating technologies have different
pollution prevention potential, broad-based environmental policy would help promote some
renewables more than others.
These results indicate that renewable electric generating options could compete extremely well
with fossil fuel alternatives if environmental performance were valued in the marketplace. The $50/ton
and $lOO/ton penalty for carbon emissions are within the range of penalties that some states are
considering applying to various pollutants from fossil fuel sources. If such penalties help guide
resource planning over the next decades, as the Enhanced Market scenario assumes, then renewable
energy stands to make significant inroads to the electric supply sector.
9O
See Environmental Costs of Electricity, prepared by the Pace University Center for Environmental Legal
Studies (New York Oceana Publications, Inc . 1990), and Olav Hohmeyer, Social Costs of Energy Consumption:
External Effects of Electricity Generation in the Federal Republic of Germany (Heidelberg: Springer-Verlag, 1988).
21 The penalties are applied to the fossil fuel mix displaced (at the margin) by specific renewable technologies.
Because the assumed marginal fuel mix does not change by the imposition of the penalties, however, only a first-
order estimate of the avoided cost increase is calculated.
Ill - 25
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CHAPTER IV
BIOMASS ELECTRIC GENERATION
Biomass is a form of solar energy stored in organic matter through plant photosynthesis. The
photosynthetic process is a complex chain of reactions that occurs in plants, where energy from
sunlight fixes carbon (from carbon dioxide in the air) with hydrogen from water, producing glucose
and oxygen. Glucose is used to synthesize longer chain hydrocarbons (polysaccharides), including
cellulose and starch, for long-term energy storage. The only major difference between biomass
hydrocarbons and the hydrocarbons that make up fossil fuels is that fossil fuels have been made
much more energy dense through thousands of years of extreme pressure and temperature.
Combustion of biomass hydrocarbons, which is essentially reverse photosynthesis, releases energy
capable of performing work in the same way that fossil fuels provide useful energy.
As with fossil fuels, the combustion of biomass results in the production of carbon dioxide, a
major greenhouse gas. However, there is no net emission of carbon when new growth of plants
sequesters (through photosynthesis) an equal or greater amount of carbon as a part of the carbon
cycle (shown in Figure IV-1). It is essential that biomass resources be properly managed to insure
that new growth and organic buildup of soils offset carbon emissions from biomass combustion,
making biomass a net sink of carbon. Combustion of biomass wastes also produces CO2 , but
recovers useful energy that would otherwise be dissipated during slow oxidation (decay) which would
yield CO2 without providing useful energy.
While biomass initially is formed as a solid (e.g., trees and other plants) the energy can be
converted to liquid and gas forms. The primary thrust of the DOE biomass research program is the
development of liquid transportation fuels, which are already used to some extent today. Anaerobic
digestion of solid hydrocarbons by microbes produces biogas (whose primary component is methane)
as a byproduct. Biomass is also gasified by thermal processes.
Traditional biomass fuelstocks used for the generation of electricity include wood, wood waste,
and agricultural waste. Municipal solid waste (MSW) is a second major biomass fuelstock that is used
for electricity production1. Biogas (methane produced by anaerobic digestion of organic matter) is
1 MSW is considered to be a renewable biomass fuelstock here, even though it contains some amount of
petroleum-based products, because it is composed largely of post-user biomass (mostly paper). It should become
even more "renewable" in the near future as plastics and other petroleum products are separated from MSW for
recycling
IV- 1
-------
FIGURE IV -1
The Carbon Cycle
FREE CO2 IN
AIR AND WATER
Source: Biological Science by William T. Keeton, (New York, NY: W.W. Norton & Company, 1980).
IV-2
-------
the third type of biomass fuelstock considered in this analysis. Liquid fuels are not considered in this
analysis of the potential contribution of renewable electric technologies because they are expected to
be devoted primarily to providing energy for the transportation sector.
For each fuelstock there are a number pathways that can be taken for conversion to
electricity. A number of technologies exist, or are being developed, for converting the energy stored
in biomass to electncity. figure IV-2 summarizes for the three fuelstocks the various conversion
pathways that can be taken to produce electricity.
This chapter is divided into four main sections. The first section briefly describes the biomass
resource bases considered in this study. The subsequent three main sections analyze the three
biomass fuelstocks: (1) wood, wood waste, and agricultural waste; (2) MSW; and (3) landfill and
digester gas. In each section, existing technologies for conversion to electricity are characterized,
followed by a discussion of emerging technologies. Each section concludes with a market
assessment of the fuelstock being considered and estimates of air pollution prevention potential.
BIOMASS RESOURCE BASE
The resource base for biomass is a function of the quantities of inputs, including land,
machinery, and labor, devoted to biomass production as well as the productivity of the plant species
and the land. Since biomass is a photoconversion process, like photovoltaic and solar thermal
electric, its total resource base is limited in theory by the amount of solar insolation received by land
upon which biomass can be grown (and by the availability of water and nutrients required for growth).
TOTAL U.S. RESOURCE BASE
A recent study conducted by Meridian Corporation for DOE estimates the 30 year
photoconversion energy resource at one million quads.2 This value is the product of the average
daily incident radiation on the surface of the U.S., about 4.32 kWh/m2, and the proportion of the
radiation which Meridian considers intense enough to be a potentially exploitable resource, which they
estimate at 70%. Approximately 45% of the U.S. surface area is committed to uses such as national
parks and cropland, which limits the accessible photoconversion resource base to approximately
600,000 quads. Biomass energy could account for only a portion of these totals, as the three
photoconversion processes (PV, solar thermal, and biomass) are mutually exclusive. The estimated
«
Characterization of U.S. Energy Resources and Reserves, prepared for the U.S. Department of Energy by
Meridian Corporation, June, 1989. A quad is one quadrillion (1015) Btu.
IV-3
-------
FIGURE IV - 2
Biomass Conversion Pathways
Processes
End uses
Direct
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Remove
C02
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Electricity
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Steam
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Electricity
Cooking
Stationary engines
Fuel gas pipeline
Mobile engines
Stationary engines
Gas turbinesfEtoctricfty)
Space & water heat
Cooking
Process heat
Steam
Electricity
Space & water heat
Process heat
Steam
Stationary engines
Mobile engines
Natural gas pipeline
Examples of how biomass can be processed
Process number:
1.2,3.4
2.3.4
1.2.3.4
1,2.3.5
5
5
5
(see boxes above)
Wood & wood wastes
Agricultural crops
Crop residues
Municipal solid waste
Sewage sludge
Animal wastes
Aquatic plants
Source: Changing by Degrees, Office of Technology Assessment, 1991.
Draft - Do Not Quote or Cite
IV-4
September 26, 1991
-------
economic reserves of biomass represent a small fraction of this potential, amounting to about 10
quads per year.
An alternative estimation, based on more realistic assumptions concerning biomass
photoconversion and the availability of biomass resources for energy production, places the
theoretical maximum accessible resource base for biomass energy in the year 2000 at 54.9 quads.
Approximately 14.6 quads, roughly 25 percent of the total, is potentially recoverable when considering
the time and economic constraints that limit the installation of additional conversion equipment.3
These estimates of the total and recoverable biomass resource base, and estimates for the various
biomass sub-components, are presented in Table IV-1.
Biomass fuels generally come from one of two sources: (1) growing stocks of biomass, either
trees or devoted energy crops, that are harvested specifically for conversion to electricity or (2) waste.
Biomass as waste can exist in many forms, including municipal solid waste, agricultural and forestry
residues, industrial waste (wood pallets), mill wastes (including waste wood and waste heat from mill
operations used for cogeneration), and manure. While it is not desirable to maximize the production
of by-products and waste for the sake of the energy they contain, the economic value of wastes
ultimately generated can be maximized through conversion and/or recycling, often with positive
environmental impact. The economic potential for transforming biomass wastes into useful energy is
limited by the ability to collect and concentrate them for conversion. Growing stocks of biofuels, on
the other hand, offer almost limitless potential for expansion. Maximization of this energy source can
be achieved by dedicating more and/or better land to the production of dedicated energy crops and
by increasing the productivity of species used. The widespread planting of Short Rotation Woody
Crops (SRWC) is one way to increase output from this source, and has been estimated by DOE in a
preliminary analysis to offer the annual potential for an additional 9 quads of energy, using
conservative assumptions on land availability and economic feasibility.
In the U.S., biomass provides roughly 3 quads of primary energy, mainly for heat and steam.
About 0.5 quads are used to produce electricity, with the bulk of current supply coming from
cogeneration facilities in the wood, paper, and pulp industries. Many more resources are potentially
available for expansion of biomass energy utilization. However, higher valued uses of these
resources, inefficient resource management, and transportation constraints, among other factors, have
all combined to raise fuel prices and add to supply uncertainties that compromise the economic
viability of biomass electric generation.
3 These figures are taken from The U S Biofuels Industry" by Donald Klass found in Energy from Biomass and
Waste XIII. (Chicago: The Institute of Gas Technology), 1990.
IV-5
-------
TABLE IV - 1
BIOMASS ENERGY CONSUMPTION AND POTENTIAL AVAILABILITY
(quads)
RESOURCE
Wood and Wood Wastes
Industrial
Residential
Commercial
Utilities
Total
MSW (RDF and Mass Burn)
Agricultural & Industrial Wastes
Methane
Landfill Gas Recovery
Digester Gas Recovery
Thermal Gasification
Total
Other Biomass
Ethanol
Other Biofuels
Aquatic Biomass
Miscellaneous Wastes
Total
TOTAL
1987
Biomass
Consumption
1.85
0.84
0.022
0.009
2.72
0.11
0.04
0.009
0.003
0.001
0.013
0.07
0.0
0.07
2.95
2000
Biomass
Consumption
2.1
1.0
0.04
0.01
3.15
0.60
0.08
0.100
0.004
0.002
0.106
0.1
0.1
0.2
4.14
Estimated
Recoverable
10.4
1.8
1.2
0.2
0.15
0.35
0.8
0.05
0.85
14.6
Theoretical
Maximum
25.0
2.0
17.1
1.0
1.1
2.1
7.7
1.0
8.7
54.9
Source: Adapted from The U.S. Biofuels Industry,' by Donald L Klass in Energy from Biomass and
Wastes XIII, ed. Klass, (Chicago: Institute of Gas Technology), 1990.
IV-6
-------
GEOGRAPHIC DISTRIBUTION
Table IV-2 presents current biomass electric capacity for wood and wood wastes, MSW,
agricultural wastes, and landfill and digester gas for the twelve EPA model regions. As seen in this
table, all regions have some biomass capacity, reflecting the maturity of this technology and the
widespread availability of biomass fuels. The regional distribution of agricultural and silvicultural
industries and MSW generation will determine the geographical range of future biomass fueled electric
generation.
Wood and wood waste, the predominant biomass fuel, is available to some extent in all
regions. However, these resources are generally concentrated in the traditional timber regions in the
South, Northwest, and Northeast. Table IV-3 shows a projection of wood fuel use based on 1987
geographical patterns and a projection of total use in 2000. The South uses more than twice as much
wood fuel as any other region. However, utility fuelwood use in all regions is currently very low
compared with non-utility sources of generation (e.g., wood mill cogeneration); the national total was
less than 0.01 quads in 1987. Limited commercial tree production for energy use occurs on roughly
50.000 acres in seven states, as shown in Table IV-4.
MSW resources (for mass burn, refuse-derived fuel, and landfill and MSW digester methane)
generally follow regional population distribution. Regional estimates of current MSW generation and
waste-to-energy capacity are presented in Table IV-5. Only Arizona/New Mexico, with some of the
strictest air quality control standards in the country, currently lacks waste-to-energy capacity.
WOOD, WOOD WASTE, AND AGRICULTURAL WASTE
Wood and wood wastes together represent the single largest source of biomass fuel for
electricity generation. Agricultural wastes (com husks, nee husks, sugar cane residue, etc.) offer an
additional source of fuel where they are geographically concentrated enough to be brought to a
central site economically.
CONVERSION TO ELECTRICITY
Electricity has been produced from wood and, to a lesser extent, agricultural fuelstocks for
many years. The technologies are well established and can be used to produce electricity
economically in areas where biomass fuels are concentrated and available at low (or zero) cost.
IV-7
-------
TABLE IV - 2
BIOMASS ELECTRIC CAPACITY BY REGION IN 1990
(megawatts)
REGION
New England
Mid Atlantic
South Atlantic
Flonda
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
Total
Wood and
Wood Waste
716
90
936
553
387
126
967
318
82
56
628
567
5.427
Municipal
Solid Waste
470
442
123
142
172
70
7
0
32
0
60
66
1.584
Agricultural
Waste
0
*
0
60
0
9
25
15
0
1
0
0
110
Landfill and
Digester Gas
23
110
*
2
55
2
3
13
8
3
259
10
489
Biomass
Total
1,210
642
1,059
757
614
208
1,002
346
122
60
947
643
7,610
* Indicates electricity capacity of less than 0.5 MW.
Note: Totals may not equal sum of columns due to independent rounding.
Source: The Power of the States, by Nancy Rader. (Washington DC: Public Citizen) June, 1990.
IV-8
-------
TABLE IV - 3
WOOD FUEL CONSUMPTION BY END USE AND REGION IN 1987
(trillion Btu)
Region
Northeast
South
Midwest
West
Total
Residential
Total
166
264
250
172
852
Industrial
Total
182
883
222
290
1,576
Electric1
35
168
42
55
299
Utility
Total
1.6
0.0
2.1
4.9
8.6
Total
Total
350
1,147
474
467
2,437
Electric
37
168
44
60
308
1 Assuming that 19% of industrial cogeneration is for the production of electricity. Based on data in
Table B-5 of The Potential of Renewable Energy, Interlaboratory White Paper, (Golden, CO: Solar
Energy Research Institute, March 1990).
Source: Estimates of Biofuels Consumption in the United States During 1987 (Washington, DC:
Energy Information Administration), 1989.
IV-9
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Existing Technologies
Direct combustion of wood and agricultural fuelstocks typically involves modifications of the
technologies used to burn coal and include the following basic combustion system configurations: (1)
pile burners involve the distribution of biomass fuel of variable dimensions to the furnace through an
underfeed, overfeed, or spreader stoker with the fuel being piled on a grate to burn; (2) cyclone and
suspension burners force the particulate biomass fuel into the combustion chamber with a
pressunzed air stream; (3) fluldized bed burners are similar to suspension burners but add a hot bed
material such as sand or crushed limestone.
The DOE Clean Coal Technology Program (CCTP) has been exploring utility-scale
atmospheric fluidized bed combustors (AFBC), a technology that has been used in smaller
applications, primarily for coal, for many years. DOE expects utility-scale AFBC to be commercially
available between 1995 and 2000, with widespread applications that could include biomass in addition
to coal possible between 2000 and 2005.4 In the near term, however, smaller scale AFBC offer the
potential for immediate expansion of biomass electric capacity.
One of the key advantages of AFBC is fuel diversity, as demonstrated by successful operating
experience at the Northern States Power French Island powerplant. French Island Unit 2 was
retrofitted with AFBC in 1981, and Unit 1 was retrofitted in 1987; the plant currently burns a 50/50
mixture of wood waste and refuse-derived fuel.5 A wide range of biomass/coal blends could also be
burned in AFBC boilers. Utilities considering AFBC as a compliance option for revised Clean Air Act
requirements may consider the partial or exclusive use of biomass fuels for these boilers. While CCTP
funding of AFBC demonstrations is intended to expand the use of coal, stronger emphasis on
biomass potential for demonstration projects is certainly consistent with the DOE goal of enhancing
domestic energy capacity.6
As utilities face investment choices to maintain generation from older coal plants (about 200
gigawatts of coal-fired capacity -- more than two thirds of current capacity - will be over 30 years old
by 2010), repowering with AFBC boilers would represent a significant opportunity for expanding
4 See Clean Coal Technology: The New Coal Era (Washington U.S. Department of Energy), November, 1989,
p36
5 See "Waste Fuel Firing in Atmospheric Fluidized Bed Retrofit Boilers" by Jerome R. Zylkowski and Rudy J.
Schmidt, in Klass. ed Energy from Biomass and Wastes XIII
6 Although AFBC eliminates a large percentage of conventional air pollutants from coal, such as SO2 and NOX,
the CO2 emissions per kWh is actually slightly higher than a conventional coal plant because AFBC plants
generally have slightly higher heat rates This underscores the need to consider co-firing coal with biomass fuels.
IV- 12
-------
biomass utility generation and reducing coal use. Advancing biomass-compatible technologies would
also promote U.S. technology export, since many countries have greater access to biomass fuels than
coal.
Because biomass combustion technologies are based largely on existing coal combustion
systems, direct combustion of biomass offers a unique opportunity of directly backing out coal
consumption. The Santee Cooper electric utility in South Carolina has been cofiring waterlogged
waste wood from hurricane Hugo at its Jeffries coal steam plant at a rate of 10 percent by weight
without any decrease in efficiency.7 Their experience suggests that wood fuel can be cofired with
coal at a rate of up to about 20 percent by weight in some cases without derating the boiler.
Throughput is limited by moisture content and chip size, so it is conceivable that smaller chips, dried
using waste heat, could increase the potential for wood cofiring. Since combustion of wood fuel
results in emissions of only trace amounts of SO2 and NOX, cofiring wood with medium to low sulfur
coal could present a simple cost effective way of bringing existing plants that burn high sulfur coal
into compliance with new Clean Air Act requirements. Refuse-derived fuel (RDF) processed from
municipal solid waste represents another co-firing option that could reduce SO2 emissions by
displacing 10% to 20% of coal in an existing boiler.8
Wood has a heat content that is somewhat lower than most coal, with roughly 8 million Btu
(mmBtu) per ton of green wood (about 17 mmBtu per dry ton)9 compared to average values of 14
mmBtu for lignite, 18 mmBtu for sub-bituminous, and 24 mmBtu per ton of bituminous coal. Because
the low energy density of wood requires a much greater volume of wood fuel than coal, burning only
wood could limit total capacity due to constraints on transporting wood to the plant. The handling
requirements of the two fuels are fairly similar once the wood fuel has been chipped. In fact, coal
pulverizing equipment has been used at the Jeffries plant without any modifications to pound wood
chips into particles for suspension burning, demonstrating that an existing coal-fired plant can use
biomass fuelstocks with only minor modifications to fuel handling and processing equipment.
7 See "Wood Chips Making Electricity" in The Logger and the Lumberman, May 1990.
8 See 'Effect of Co-combusting Refuse-derived Fuel and Coal on Emissions of SOX, NOX, and Ash from Coal-
Fired Boilers," by Glenn A. Norton and Audrey D Levine, in Energy from Biomass and Wastes XIII, ed. Donald
Klass. (Chicago Institute of Gas Technology). 1990
Q
The dry wood measure is used to normalize data and is defined as oven-dried wood having no water content,
whereas green wood typically has a moisture content of 50 percent by weight. In practice, wood is not oven dried
before being used, although in some systems it is dried to less than 25% water using waste heat.
IV-13
-------
Current Economics
Technologies for biomass conversion are well established, and are based on existing fossil
fuel technologies. Competition with fossil resources for electricity generation is generally based on the
relative pnces of fuel inputs.
The capital costs of a conventional wood or agricultural waste fired electric generating plant
range from $1,500/KW to $2,000/KW for plants between 30 MW and 50 MW. Because of the moisture
content of bionass fuel, heat rates in the range of 12,000 to 16,000 Btu/kWh are typical. With the cost
of biomass fuel in the range of $1.00 to $3.00 per million Btu, levelized generation costs are between 4
and 8 cents/kWh.
EMERGING TECHNOLOGIES
Biomass electric generation on a utility scale is not constrained by technology; in fact,
biomass combustion technologies are very mature compared to some other renewable technologies.
There are emerging conversion technologies that should make electricity generation from biomass
more economic, including whole tree combustion and biomass gas turbines. The major factor
currently constraining biomass electric generation is the economics of fuel supply. Emerging biomass
production techniques, primarily the development of short rotation woody crops (SRWC), should
dramatically increase the economic reserve of biomass fuelstocks in the coming decades.
Emerging Conversion Technologies
Continued advances in the fuel flexibility of coal technology may expand the amount of utility
capacity that could use biomass fuels. Developing a whole tree combustion technology and a
biomass gasifier driving a gas turbine or combined cycle steam turbine holds promise for increasing
combustion efficiencies and minimizing costs of electricity generation from biomass. Examples of
specific emerging biomass combustion technologies include:
Whole Tree Energy. A promising new approach to biomass combustion is the Whole Tree Energy
(WTE) power generating plant developed by Energy Performance Systems, Inc.10 This new
technology lowers the overall generating costs for wood-fired generating plants by increasing the
efficiency of wood handling and combustion, while also reducing emissions. Because the facility uses
whole trees rather than processed wood chips, its fuel handling costs are less than traditional wood-
10 See "Whole-Tree Combustion Avoids Fuel Preparation,' by Jason Makansi in Power, October 1990.
IV-14
-------
fired plants. To improve the fuel, the WTE uses waste heat to dry the trees prior to combustion
(reducing average moisture content from about 50% to under 25%). The boiler creates steam which is
directed through a turbine to produce electricity in the conventional manner.
The pile-type combustor uses a three stage combustion process to burn the trees. The first
stage of combustion occurs in the bed under oxygen-deficient (substoichiometric) conditions, during
which volatile gases are emitted. These volatile gases are combusted in the second stage above the
bed at very high temperatures (2700°F). Char produced in the first stage falls through the grate where
it is combusted in the third stage. This combustion process results in a relatively high furnace
efficiency (—87%) contributing to an overall power plant cycle efficiency of 33% - 36% as compared to
conventional wood power plant cycle efficiencies of 20% - 30%. These increases in efficiency over
conventional wood-burning technologies result in a much lower heat rate, about 10,000 Btu per
kilowatt hour for WTE, compared to about 12,000 to 16,000 Btu per kilowatt hour for conventional
wood-fired plants.
The lower heat rate, stemming from increased cycle efficiency, and lower capital and operating
costs compared to conventional wood-burning plants, result in markedly lower levelized generation
costs using WTE. Fuel costs related to harvest, preparation, and transport are reduced by using
whole trees, rather than wood chips. Levelized fuel costs are reduced even further due to the lower
heat rate for WTE. Relative electricity generation cost reductions associated with the use of WTE are
illustrated in the first two bars of the graph presented as Figure IV-3.
New WTE plants could range in size from 25 to 400 MW, and the WTE system could also be
used to retrofit old or out-of-service coal-fired plants. For both types of plants, fuel supply issues,
such as the capacity for developing short rotation energy plantations nearby, are important factors
involved in selecting plant sites. The WTE technology is in the development phase and has not
currently been used commercially to generate electricity. Conversion of a coal-fired plant to a 60 to 80
MW WTE demonstration plant should be completed by the end of 1992. It is expected that once the
technology is established, coal plant conversion would take about eighteen months and that
construction of new plants will take two to three years.
Blomass Gasification and Combustion. The gas turbine is an existing technology widely used in
natural gas power generation. Gas turbines are especially suited to biomass applications, because of
their high thermodynamic efficiency compared to steam turbines, in small to medium size utility
applications up to about 50 MW. In cogeneration applications, steam cycle generators have a thermal
IV-15
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efficiency of 28 percent and a total efficiency of 35-62 percent, compared to 50 percent thermal
efficiency and 76-81 percent total efficiency for gas turbines.11
The use of biomass fuelstocks does present some technical difficulties that require
modification of existing gas turbine technologies. Currently, the major technical difficulty limiting the
use of this technology is deposition on gas turbine blades. Hot gas cleanup technologies are
advancing rapidly, however, and it is expected that over the next two decades these technologies will
be refined to a point where deposition on the turbine blades no longer inhibits the use of directly-fired
biomass gas turbines.
Thermal gasification involves heating biomass fuelstocks in a chamber containing air or pure
oxygen, producing a low to medium Btu gas (100-250 Btu per standard cubic foot). Pyrolysis, an
extreme form of thermal gasification, involves heating biomass fuelstocks at very high temperatures in
the absence of any gases, producing a higher Btu gas (600-900 Btu/scf). Currently, air-blown reactors
have the most potential for commercial application. The reactor can have either a fixed or fluidized
bed. Fluidized bed reactors provide for more fuel flexibility, but result in higher levels of particulates in
the hot gas. The hot gas is passed through cyclones to clean it of particles before being flashed in a
combustion chamber to drive a gas turbine, generating electricity. Efficiencies can be increased by
using combined cycle and steam-injected cycle technologies. In the steam-injected gas turbine
(STIG), exhaust gas is used to produce steam that is injected into the pyrolytic chamber to augment
power and efficiency by increasing hydrogen production. Figure IV-4 illustrates the processes
involved in biomass gasification and combustion for a steam-injected gas turbine. STIG technology is
especially useful in cogeneration applications where steam production is greater than the need for
process heat. Gas turbine technology is commercially available now for fossil fuels, with ongoing
research being conducted on improving hot gas cleanup technologies to increase operating efficiency
with solid biomass fuels.
Costs
According to Energy Performance Systems, Inc, the developer of Whole Tree Energy, installed
costs of a new WTE will range from $800 to $1100/KW. The installed costs for retrofitting an existing
coal-fired plant range from $300 to $400/KW.
11 See 'Biomass Gasification for Gas Turbine Power Generation" by Eric Larson, et. al., in Electricity: Efficient
End-Use and New Generation Technologies and Their Planning Implications, Thomas B. Johansson, Birgit Bodlund
and Robert H Williams, eds (Lund, Sweden Lund University Press, 1989).
IV- 17
-------
FIGURE IV - 4
Biomass Gas Turbine Schematic Diagram
FUEL
GAS
BIOMASS
FEEDSTOCK
TO
STACK
1
HEAT
RECOVERY
STEAM
GENERATORS
STEAM INJECTED
GAS TURBINE
AIR
C:
GT:
Compressor
Turbine
C: Generator
COMB: Combustor
Source: 'Biomass Gasification for Gas Turbine Power Generation" by Eric Larson, et. al in Electricity:
Efficient End-Use and New Generation Technologies and their Planning Implications, Thomas. B.
Johansson. Brigit Boblund and Robert H. Williams, eds. (Lund, Sweden: Lund University Press, 1989).
IV- 18
-------
Biomass gas turbines generally have an installed cost between $900 - 1100/KW depending on the
cycle configuration (i.e. combined cycle vs. steam injected). Depending on fuel costs (ranging from
$2.50-3.00/mmBtu), generation costs for STIG range from 4.3 to 5.7 cents/kWh, roughly comparable to
gas turbine posts for coal gasification and combustion.
Emerging Biomass Production Technologies
While advancements in biomass conversion technology will improve the economics of
electricity generation, the primary obstacle confronting the biomass electric industry is the availability
of inexpensive, reliable fuelstocks. Two means of increasing the availability of inexpensive biomass
resources are: 1) increasing the recovery and use of wood, agricultural, and municipal solid wastes
and 2) using short-rotation woody and herbaceous crops as feedstocks.
Increased Recovery of Biomass Wastes. Wood waste or logging residue is often produced from
thinning of commercial stands, and from clear-cutting, where some waste must be removed in order to
replant new trees. An estimated potential of 10.4 quads of energy could be recovered from wood
waste by the year 2000. The cost of wood waste ranges from $1 to $3.30 per mmBtu and the cost of
recovering logging residues is usually paid by the fuel user. In rural areas, slashing (open-air burning)
of wood waste is preferred to disposal because of the cost of transporting the waste out of the forest.
Possible future environmental regulations on slashing may force land managers to seek alternative
waste disposal options, including increased utilization for energy.
Wood waste may also be generated from a secondary source such as mill residue, where
waste transportation costs often keeps it on-site for use in cogenerating power for the mill. Mill
wastes, however, are almost wholly utilized at present and are not expected to grow much in the
future. In fact, residue factors (tons of residue per board feet) in the Pacific Northwest are expected to
decrease by 30 percent over the next 20 years mainly because the pulp and paper industry is
producing less waste and harvesting less old growth material.12
Agricultural waste includes the residues that remain after harvesting and the secondary
residues that remain after the harvested crop is processed. About one quad of potential energy is
estimated to be recoverable from agricultural residue in the year 2000. The use of agricultural
residues as a feedstock for a stand-alone system faces the institutional problems and costs of
collecting, storing, and delivery of residues from several individual farms to a power plant.
12 See 'Biomass Resources.' by James D. Kerstetter, (Portland, OR: Northwest Power Planning Council,
October 16, 1989).
IV-19
-------
While the use of existing biomass fuel sources can be expanded, especially the use of logging
and construction waste wood and better management of underutilized forests, potential limitations and
competing uses suggest that additional economic fuel sources will need to be developed in order for
biomass electricity capacity to grow appreciably. Short-rotation woody crops (SRWC) offer the
potential for dramatic growth in the supply of biomass fuels.
Short-Rotation Woody Crop (SRWC) Feedstocks. The potential for fast-growing, short-rotation fuel
wood plantations is being explored as a means to develop a low cost, reliable fuel source.
Biotechnology research seeks to improve the productivity of hybrid biomass energy crops through
selection and genetic alterations. In demonstration stands and pilot projects, SRWC have been grown
successfully in most regions of the U.S., using species tailored to each region and land type.
Table IV-6 lists representative species for various regions of the country, presents aggregated data on
current yields and costs, and defines SRWC program goals.
Currently, crops are harvested every 3 to 10 years with average annual yields of 3 to 8 dry
tons per acre per year. The goal of the SRWC program is to achieve yields of 8 to 12 dry tons per
acre per year. Although SRWC yields can be high on marginal croplands, optimum conditions and
intensive culture are needed to achieve maximum yields.
The amount of land potentially available for SRWC plantations dedicated to energy crops
depends on the economics of biomass fuels, including the relative prices of fossil fuels and other,
higher valued uses, like food crops and fiber. The potential land base for energy crops is enormous,
with estimates ranging from 78 to over 230 million acres, including both marginal land and surplus
prime cropland.13 If 230 million acres were planted with crops yielding 5 dry tons per acre per year
(a conservative estimate of future SRWC yields), over 13 quads of primary energy equivalent could be
produced each year.14
Even greater production can be achieved by increasing yields of SRWC species. For
instance, increasing the yield per acre from 5 to 6 dry tons would boost the energy potential for
planting on 230 million acres from 13 to 16 quads. All other things being equal, unit costs of
production should decrease in proportion to the increase in productivity. Higher land and treatment
13 See 'Expanding the Market by Improving the Resource' by LL Wright, et. al, Bioloque (June/July/August
1989)
14 Assuming a heat content of 17 x 106 Btu per ton of dry wood and an electric conversion factor for wood of
15.000 Btu/kWh The current average fossil fuel conversion factor in the U.S. (10,253 Btu/kWh) is used to calculate
primary equivalent Improvements in combustion technology to 10,000 Btu/kWh would bring the primary energy
potential to almost 20 quads per year
IV-20
-------
TABLE IV - 6
SHORT ROTATION WOODY CROPS (SRWC) PROGRAM STATUS AND GOALS BY REGION
Regions/Promising Species
Pacific Northwest
Black Cottonwood
Hybrid Cottonwood
Red Alder
Subtropics
Eucalyptus
Lake States/Midwest
Hybrid Poplar
Alder
Black Locust
Willow
Aspen
Ailanthus
Siberian Elm
Silver Maple
Autumn Olive
South
Sycamore
Black Locust
Cottonwood
Sweetgum
Northeast
Hybrid Poplar
Black Locust
Maple
Semiand Southwest
Mesqurte
Fourwing Saltbush
Current Research Status
Average Yield
Dry T/acre/yr
8
8
4
3
5
NA
Average Cost
$/mmBtu
2.20
2.20
3.00
3.30
3.00
NA
Program Goals
Average Yield
Dry T/acre/yr
12
12
9
8
8
NA
Average Cost
$/mmBtu
1.90
1.90
1.90
1.90
2.30
NA
NA: Not Available.
Source: Adapted from 'Accelerating Energy Crop Growth Via Genetic Techniques," by Patricia
Layton, et. al, in Energy from Biomass and Wastes XIII, ed. Donald Klass, (Chicago: Institute
of Gas Technology), 1990.
'Short Rotation Intensive Culture for the Production of Energy Feedstocks in the US: A
Review of Experimental Results and Remaining Obstacles to Commercialization,' by R.D.
Perlack, et. al, Biomass 9(1986) p. 145-159.
IV-21
-------
costs would most likely offset the reduction in unit costs, but in some cases the increase in
productivity could be greater than the increase in input costs, causing unit costs of production to fall.
Higher productivity could decrease fuel delivery costs as well, if a greater proportion of wood fuel is
produced closer to the point of consumption. The relative effects of increased productivity on
levelized electricity generation are illustrated in Figure IV-3.
There are many advantages of short rotation energy crops in addition to providing an
abundant source of fiber or biomass energy fuelstocks. SRWC crops generally require less
maintenance than traditional food crops, requiring weed control only through the first year or two of
growth. Additionally, fewer chemical fertilizers and herbicides are needed compared to commercial
food crops, reducing groundwater impacts. Woody crops can also be used to treat waste water and
sewage sludge by recycling nutrients in these wastes. Organic wastes produced by municipalities
and industries are often treated in large, capital intensive water treatment plants, with sewage sludge
often landfitled in the end. An alternative organic waste treatment and disposal strategy is to couple
waste water treatment with SRWC technology. Some cities, including Seattle, Washington and
Edenton, North Carolina have already established SRWC plantations for waste disposal. SRWC waste
treatment involves pumping organic wastes onto a SRWC plantation where the rapidly growing trees
recycle the nutrients, preventing them from fouling surface and groundwater. Prior treatment of the
waste may be needed in some instances to remove heavy metals and other pollutants that may not
be adequately removed by the growing trees. If this practice is found to be environmentally
acceptable on a large scale, SRWC production could increase considerably.
MARKET ASSESSMENT
Table IV-7 shows the DOE/SERI projections and EPA technology penetration scenarios for
wood and wood waste generation. The EPA Base Case for wood and wood waste essentially equals
the DOE/SERI Business as Usual Scenano, where electricity generation is projected to equal about 70
million MWh in 2000 and over 100 million MWh in 2010.
The EPA Enhanced Market scenario for solid combustion biomass electric generation builds
on the DOE/SERI National Premiums projection. This assumes that market enhancement would
stimulate existing markets for wood, wood waste, and agricultural waste fuel in much the same way as
premiums placed on fossil fuel generation. Assuming that these traditional biomass sources are
exhausted under the DOE/SERI National Premiums projection, the bulk of the increased biomass
generation in the EPA Enhanced Market scenario comes from an aggressive short-rotation woody
crop (SRWC) planting program for marginal or environmentally sensitive crop and pasture land. Most
of this land is being eroded rapidly by either wind or water, and requires the planting of a cover crop.
IV-22
-------
TABLE IV - 7
WOOD AND WOOD WASTE SCENARIOS
Scenario
DOE/SERf
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
-------
million Btu (mmBtu). This assumes that all SRWC supply is utilized as fuel for electric power; other
higher valued uses for the crops, such as pulp or liquid fuel production, could limit the fuel supply for
electric power. Fuel prices for SRWC range from about $2.10/mmBtu in Washington/Oregon to almost
$3.50/mmBtu in the Northeast. Costs and emissions for both EPA scenarios are calculated under the
assumption that 75% of the wood-fired capacity built between 1990 and 2000 would be conventional
plants, and the other 25% would be Whole Tree Energy (WTE) systems. Between 2000 and 2010, the
Base Case assumes that conventional systems and WTE systems each gain 50% of the market, while
in the Enhanced Market scenario, conventional systems account for 40%, WTE systems account for
40%, and biomass gas turbines account for 20% of new capacity built.
The incremental generation, costs, and air pollution prevention potential for wood fueled
electricity generation are shown on Tables IV-8 and IV-9. The growth of wood-fired generation in the
Base Case is concentrated in the South (South Atlantic, East South Central and Florida regions) and
far West (California and Washington/Oregon). The increased generation in the Enhanced Market
scenario reflects the vast potential for SRWC in the Central regions. More than two-thirds (68%) of the
1990-2010 incremental biomass solid generation occurs in East and West North Central and East and
West South Central regions.
Costs
In the Base Case, the average cost of solid biomass combustion is roughly 8.0 c/kWh in 2000,
or 3.0 c/kWh more expensive than conventional fossil fuel baseload generation. This cost falls to 7.0
C/kWh by 2010, when biomass solid combustion is only 0.6 c/kWh more expensive than conventional
energy sources. Costs are similar in the Enhanced Market scenario, reflecting the fact that policies to
stimulate a rapid expansion of wood-fueled electric capacity would be necessary to overcome the
relatively high fuel prices for solid biomass fuels. In the Enhanced Market scenario, this stimulus
comes from a recognition of the environmental benefits of biomass fuels (e.g. the 2 0/kWh premium
assumed in the DOE/SERI National Premiums case) that results in increased use of traditional
biomass sources as well as an aggressive SRWC fuel supply program. It is also important to note
that these cost figures do not include the substantial environmental benefits obtained by reducing
topsoil erosion from the SRWC planting program.
Costs variation is evident across regions in both scenarios. In the Base Case, traditional
commercial wood product industries supply fairly low cost fuel in the Northeast and
Northwest/Mountain regions. By 2010, biomass generation is less expensive than conventional
generation in the Northeast and California, in part because of high avoided costs in those regions.
Regional costs in the Enhanced Market scenario are somewhat different. The costs in the Northeast
IV-24
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lower in other regions. Avoided costs are lower in the North Central region (where a large amount of
SRWC fuel can be grown) than in other regions, resulting in a cost differential of 1.2 c/kWh for wood-
fired generation in this region.
Air Pollution Prevented
An expansion of biomass solid fuel-fired electricity would reduce NOX, SO2 (or create emission
allowances under the new Clean Air Act), CH4 and CO2, but would slightly increase CO and PM from
electricity generation. In the Enhanced Market scenario, 818,000 metric tons of NOX could be
prevented annually in 2010, and allowances for 2.5 million metric tons of SO2 could be obtained.
About 321 million metric tons of CO2 could be prevented, assuming that solid biomass fuels are
grown on a sustainable basis. Although the increased emissions of CO and PM warrant concern, they
are relatively small compared to other sources of these pollutants. For example, the 29,000 metric ton
increase in PM represents only 7% of 1988 utility PM emissions (and a negligible fraction of PM from
all sources), while the 480,000 metric ton increase in annual CO emissions represents only 0.8% of
CO emission from all sources in 1988.
MUNICIPAL SOUD WASTE
Characteristics of MSW vary considerably by regional demographics, local waste management
laws (i.e. recycling programs), season, relative contribution of commercial and residential wastes,
among other things, but can be described generally as being composed of about 70-75 percent
organic matter (mostly paper) and containing about 4,500 Btu/lb. The organic component of MSW,
comprised mostly of wood and paper wastes, can be separated from the waste stream in a resource
recovery plant and processed to form refuse-derived fuel (RDF). RDF is a higher energy fuel (about
6,000 Btu/lb) that can be burned alone or with other biomass fuelstocks.
CONVERSION TO ELECTRICITY
Existing Technologies
'Mass burn' MSW combustion systems are similar to coal combustion technologies, although
significant modification of these technologies is required because of the unique characteristics of
MSW fuelstocks. RDF combustion systems are similar to conventional coal or wood-waste boilers,
and some RDF plants can utilize RDF mixed with coal or wood waste. With both RDF and mass burn,
flue gases must be cleaned to remove pollutants. The flue gases pass from the incinerator through a
IV-27
-------
lime spray dry scrubber that removes sulfur dioxide (SO2), hydrochloric acid (HCI), and other gases
and then to a bag house that captures fly ash containing heavy metals, dioxins, furans, and other
toxic compounds. Fly and bottom ash, because they contain these toxins, must be treated as a
special waste. One way to dispose of incinerator ash is to place it in a lined landfill dedicated to
incinerator ash and to monitor for any leaching that might occur.
Current Economics
MSW combustion is relatively costly due to the need for extensive pollution controls, ash
landfilling costs, higher fuel handling costs due to the bulky nature of the fuel, and low energy content
of the MSW. Waste disposal needs, and not the economics of energy production, determine whether
waste-to-energy plants are built. However, if a community decides to incinerate waste, revenues from
electricity sales can help offset the costs of waste disposal so that waste-to-energy plants can provide
for waste disposal at a lower cost in certain areas.
The cost of a municipal solid waste-to-energy plant can range from $4,750/KW to $5,100/KW
for capital and fixed operating costs and from 10 to 20 mills/kWh for operating costs, depending on
whether mass bum or RDF technologies are used. Costs for RDF facilities are generally at the high
end of these ranges because of the greater plant complexity and fuel handling requirements. The
high cost of waste-to-energy facilities is partially offset by the negative fuel cost, i.e the cost of
alternative waste disposal options. As shown on Table IV-5, tipping fees for MSW disposal range from
over $100/ton in some urban areas of the Northeast to less than $20/ton in less densely populated
areas. Tipping fees are generally set by the municipality with the intent to cover a portion of the costs
of a waste-to-energy plant, with tax revenues and electricity sales revenue accounting for the
remaining costs and profit for the operator.
EMERGING CONVERSION TECHNOLOGIES
The primary emerging conversion technology for combustion of MSW is the atmospheric
fluidized bed burner (described in the preceding section on wood and agricultural fuelstocks). The
development of 'clean' burning technologies for MSW combustion is paramount to its future viability.
Many of the pollution-related institutional bamers surrounding MSW combustion can be overcome by
combining source separation and RDF production with combustion technologies like AFBC.
Thermal gasification of RDF fuelstocks for gas turbine electrical generation is an additional
conversion pathway currently being developed for MSW. Development of this technology is following
IV-28
-------
the same path as described in the preceding section and could provide a viable alternative to direct
combustion technologies.
The amount of municipal solid waste available for energy conversion is much larger than
current use, which is a little more than 0.1 quads. Only about 12% of MSW is incinerated, and not all
incinerators have waste-to-energy conversion equipment. The remainder is currently landfilled,
sequestering carbon in the short to medium term and producing biogas in the future. Many
communities face nsing costs of waste disposal, and state and federal waste minimization policies are
likely to be implemented in the future. Even with successful waste minimization, however, future MSW
electncity production will be limited by the capacity of plants, not by availability of MSW fuel.
MARKET ASSESSMENT
The Base Case and Enhanced Market scenarios for electricity production from municipal solid
waste (MSW) are based on EPA projections of available MSW. MSW generation is expected to rise
from the current 180 million tons per year to 216 million tons in 2000 and 250 million tons in 2010. In
the Base Case, the share of MSW generation accounted for by waste-to-energy in 2000 and 2010 is
expected to equal 15% and 25%, respectively. In the Enhanced Market scenario, these percentages
are assumed to increase to 25% in 2000 and 33% in 2010. MSW could supply roughly 33 million
MWh in 2000 and 50 million MWh in 2010. These are compared with the DOE/SERI projections on
Table IV-10.
Tables IV-11 and IV-12 summarize the model results for MSW combustion. Increases in MSW
generation are concentrated in regions with significant urban populations. In the Base Case, 70% of
1990-2010 incremental MSW generation occurs in the Northeast, Southeast, and North Central
regions. These regions also account for 68% of the incremental MSW generation in the Enhanced
Market scenario.
Costs
With construction costs around $5,000 per kilowatt of capacity, MSW facilities are extremely
expensive to build. However, MSW fuel is obtained at negative costs. The cost of MSW generation is
difficult to forecast due to uncertainty over future tipping fees charged by operators to dispose of the
waste. Because of dwindling landfill space, such fees could easily rise sufficiently to dramatically
reduce the cost of MSW generation.
IV-29
-------
TABLE IV -10
MSW SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
3,400
4,500
5,800
3,200
4,900
Generation
2000
(GWh)
19,500
25,400
33,200
19,900
32,600
Capacity
2010
(MW)
7,700
9,800
14,400
5,600
7,200
Generation
2010
(GWh)
43,900
55,600
81,900
37,800
49,800
1990: 2,200 12,700
EPA did not attempt to forecast regional tipping fees in this analysis. The overall cost of MSW
generation was assumed to equal the avoided conventional cost, reflecting the widespread practice of
setting tipping fees at rates high enough to cover the MSW facility costs not recovered in electricity
sales. To the extent that the cost of alternative disposal methods rise above these implicit tipping
fees, however, the costs reported here represent high estimates of MSW generating cost.
Air Pollution Prevented
Although MSW combustion creates emissions and expanded MSW generation has only
modest net air pollution prevention potential, additional MSW generation would provide a net decrease
in NOX, SO2, CH4, and CO2. The CO2 result assumes that MSW combustion creates no net C02
emissions because the organic component of MSW would eventually oxidize and escape from
landfills. By 2010. roughly 50,000 metric tons of NOX, 220,000 metric tons of SO2, and 32 million
metric tons of CO2 are prevented in the Enhanced Market scenario. On the other hand, net CO
emissions would increase by 15,000 metric tons and PM emissions could increase by over 380,000
metric tons
IV-30
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LANDFILL AND DIGESTER GAS
Anaerobic digestion of MSW and agricultural wastes (including crop residues and animal
manure) and the capture of naturally occurring methane from landfills also contribute to energy
production from biomass. Anaerobic digestion of biomass fuelstocks produces medium Btu biogas
that can be upgraded to pipeline quality gas, although it is often more economical to burn the biogas
on site to produce electricity. Biogas is produced under anaerobic conditions as organic matter is
broken down by microorganisms. By providing optimal conditions (i.e. temperature and nutrients)
biogas production can be maximized in a digester. The design of anaerobic digesters is advancing
rapidly, with recent designs linking a number of digester tanks in series to maximize efficiency.
Landfill methane is a volatile organic compound (VOC) as well as a potent greenhouse gas
(having 20 times the impact on warming per kilogram compared to carbon dioxide over a 100-year
timeframe). Captured methane can be flared (converted to CO2), burned on-site for process heat or
steam, upgraded to pipeline quality gas, or used to generate electricity. Capturing landfill methane
that otherwise would have escaped to the atmosphere and using it to produce energy effectively
reduces greenhouse gas emissions by the amount of carbon dioxide that would have otherwise been
emitted to produce that amount of energy and the amount of methane that is captured.
CONVERSION TO ELECTRICITY
There are two stages involved with the generation of electricity from biogas. First, the biogas
must be produced and collected, then delivered to an appropriate conversion technology for electricity
generation. Figure IV-5 presents a diagram of a typical landfill gas collection and conversion facility.
Gas Production/Collection
Municipal solid waste landfills produce a gas produced through microbial degradation of the
organic component of MSW under the anaerobic conditions that commonly occur in landfills. This gas
typically consists of 55 percent methane, 44 percent carbon dioxide, and one percent other trace
gases. Landfill gas is tapped by drilling recovery wells 30 to 100 feet deep and connecting plastic
pipes from the wells to a central collection facility. The gas can then be used as a fuel source for
industrial burners, boilers or electric generation. The carbon dioxide and moisture can be also be
removed to upgrade the gas to pipeline quality, which in some cases may be a higher valued use of
biogas than electricity production.
IV-33
-------
FIGURE IV - 5
Landfill Gas Collection and Conversion
Gas Weils
and Collection System
Utility Rower Lines
Electrical Transformer
Electrical Generators
Gas Engines
Source: Power Plays, by Susan Williams and Kevin Porter (Investor Responsibility Research Center,
1989).
IV-34
-------
Municipal solid waste, agricultural and food processing wastes, and animal manures can be
anaerobically digested by microbes to produce biogas, consisting primarily of methane and carbon
dioxide. Current designs generally consist of a tank or trough into which organic matter is pumped.
The waste is mixed to insure contact with microorganisms that are found naturally in wastes. In some
cases digesters are seeded with additional microbes that have been grown in culture. As these
microbes break down complex organic molecules, they produce biogas that can be purified to contain
a higher percentage of methane. There are less than 100 animal waste digesters in the U.S., most of
which produce a medium Btu gas for on-site energy use for heat and/or electricity.
Conversion Technologies
Biogas conversion technologies are similar to those currently used for natural gas. Gas
turbines are the primary conversion technology. The gas turbine technology used for biogas
combustion is very similar to that described previously, except for gasification of the biomass
feedstock. Some amount of processing is required, especially for landfill gas, to remove contaminants
from the gas that may damage the gas turbine.
In some cases where gas production rates are not high enough to make gas turbines
economical, reciprocating internal combustion engines are used for electricity generation. In the
internal combustion engine, combustion of the gas drives pistons that turn the armature of an
electrical generator. The technology is very similar to that used in conventional diesel engine
generators.
Current Economics
Landfills with sufficient methane production rates can use gas turbines for electric generation.
These units cost about $1,700/KW and operate at high capacity factors. For large landfills, electricity
generation with turbines is becoming the preferred alternative to upgrading the gas to pipeline quality;
two gas supply projects have announced plans to install turbine generators.16 However, turbine
efficiency declines markedly when the units are operated below maximum output. In cases where
landfill methane production rates cannot support a turbine at full output, or when space constraints at
the site do not allow a turbine generator, a reciprocating engine may be used. These engines can, in
some cases, be less expensive (at $1.100 - 2,500/KW), but have higher heat rates and operating
16 The Calumet City project (6 6 MW) and the Pompano Beach project (16 MW) as noted in Power Plays
(Investor Responsibility Research Center, 1989), pp 149-150.
IV-35
-------
costs, and produce higher levels of combustion emissions. At landfills where there are limited
methane production rates, however, these engines are the most economical choice.
EMERGING TECHNOLOGIES
Research on ways to increase utilization of biogas energy is currently progressing on two
fronts. Methods for increasing biogas production and collection are being refined and additional
conversion technologies are under development.
Gas Production
Current research in the area of digester gas production is focusing primarily on increasing
digester solids concentrations (the component that is converted to methane), improving mixer designs
to increase the surface area exposed to the microbial population, and optimizing conversion efficiency
of the microorganisms. Much research into the basic biochemistry and physiology of these
microorganisms is still needed. Once these mechanisms are understood and the rate limiting steps
identified, selection or genetic improvement can be undertaken to increase conversion efficiency.
Conversion Technologies
The primary emerging fuel conversion technology for biogas is the fuel cell.17 Fuel cells are
very efficient electricity generators that rely on an electrochemical reaction between hydrogen and
oxygen, rather than combustion, to convert stored energy to electricity. Figure IV-6 shows a
schematic representation of how a fuel cell works. A hydrogen-rich gas is introduced into the fuel cell
containing an electrolyte where it releases electrons at the anode. The hydrogen ions then react with
oxygen at the cathode to form water, combining with electrons returning from the electrical circuit.
This is an exothermic reaction that produces heat as well as electricity.
Fuel cells can be used with any hydrocarbon fuel, which includes all biomass fuels, but are
currently most efficient when methane is used as a fuel source. Hydrocarbon fuels are broken down
in a fuel processor to produce a hydrogen rich gas, much like the gas used for gas turbines. Waste
heat from the fuel cell is used to raise the temperature in the processor and anode off-gas, consisting
17 For an introduction to fuel cells see 'Fuel Cells A Review of Fuel Cell Technology and its Applications." by
Leo J M J Blomen, in Electricity: Efficient End-Use and New Generation Technologies and their Planning
Implications, Thomas B. Johansson, Birgit Bodlund and Robert H. Williams, eds. (Lund, Sweden: Lund University
Press, 1989).
IV-36
-------
FIGURE IV - 6
Fuel Cell Schematic Diagram
Hydrogen-rip^
gas
Catalyst on
support matrix
Air
ANODE
<
t
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1
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t
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e ~
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clrc
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e ~
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NET REACTION
H2 * V2 0.
H.O
Source: "Fuel Cells' by Leo J.M.J. Blomen in Electricity: Efficient End-Use and New Generation
Technologies and their Planning Implications, Thomas B. Johansson, Brigit Boblund and Robert H.
Williams, eds. (Lund, Sweden: Lund University Press. 1989).
IV-37
-------
of hydrogen, carbon monoxide, and unreacted hydrocarbons, is used in the burner to lower NOX
formation.
Fuel cells produce direct current (DC) that must be converted to alternating current (AC) in
order to contribute power to the electricity supply grid. The power conditioner converts the DC that
flows from the fuel cells into grid-compatible AC. Figure IV-7 shows the design of a complete fuel cell
power plant. The fuel processor, fuel cells, and power conditioner are tightly integrated, using waste
heat from one process in another, to reduce energy loss and increase efficiency.
Electricity conversion efficiencies of fuel cells range from 40 to 70 percent. Fuel cell systems
are modular in nature and can be linked to build plants as small as a few kilowatts or as large as a
few hundred megawatts. They can be used to produce electricity for utilities, or to provide electricity
in conjunction with useful heat. For instance, fuel cells could be used in a housing complex to
provide heat and electricity to all the units.
Costs
Total installed costs for a fuel cell power plant range from $1500 to $2500 per KW depending
on production volume. The largest single cost component is the fuel processing equipment. It is this
step in the process where costs must fall for this technology to become competitive with other
conversion technologies.
MARKET ASSESSMENT
Aggregate totals of landfill gas electricity generation for DOE/SERI and EPA scenarios are
shown on Table IV-13, and the regional estimates of electric generation, costs, and air pollution
prevented are shown on Tables IV-14 and IV-15. The incremental generation in the EPA Base Case
scenario was assumed to be identical to the incremental generation in the DOE/SERI Business as
Usual Scenario. Three-fourths of the landfill methane electricity capacity growth between 1990 and
2010 in the Base Case occurs in California (53%) and the Mid Atlantic region (22%).
Since landfill gas currently accounts for about 98% of electricity generation from landfill and
digester gas, the EPA Enhanced Market scenario focuses on potential growth in this energy source.
Assuming that 65% of landfill gas from the 850 largest landfills is captured, approximately 0.1 quads of
energy will be available for electricity generation in the Enhanced Market scenario. For comparison, it
is estimated that if all landfill gas emitted annually in the U.S. were captured, approximately 0.25
quads of energy would be available for use. According to the DOE/SERI report, increased research
IV-38
-------
FIGURE IV - 7
Fuel Cell Powerplant Schematic Diagram
DEPLETED ANODE GAS
HYDROGEN-RICH
GAS
AC POWER
HEAT AND
POWER
RECOVERY
SYSTEM
POWER
LOW QftAOE HEAT
Source: 'Fuel Cells' by Leo J.M.J. Blomen in Electricity: Efficient End-Use and New Generation
Technologies and their Planning Implications, Thomas B. Johansson, Brigit Boblund and Robert H.
Williams, eds. (Lund, Sweden: Lund University Press, 1989).
IV-39
-------
TABLE IV -13
LANDFILL METHANE SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
800
1,200
900
1,100
1,500
Generation
2000
(GWh)
4,900
7.800
5,900
7,000
9,800
Capacity
2010
(MW)
1,500
2,300
1.900
1,900
2,300
Generation
2010
(GWh)
9,800
14,600
11,700
11,900
14,600
1990: 500 3.100
and development should increase the use of digester gas, especially from MSW digestion. This
growth brings the Enhanced Market fuel supply to 0.15 quads of primary energy equivalent in 2010.
Roughly two-thirds of the additional landfill gas electric capacity in this scenario is built in the
Northeast and California
Costs
Where landfill gas is available, electric generation costs are typically lower than conventional
generation.18 In the Base Case, landfill gas generation averages 0.4 e/kWh less than conventional
fossil generation in 2000, and is 2.7 c/kWh less by the year 2010. The average cost advantage of
landfill gas generation reaches nearly 3 c/kWh by 2010 in the Enhanced Market scenario.
18 Landfill gas recovery systems were not included in the costs, however, reflecting the assumption that they
would be required for non-methane VOC control reasons. Once collected, gas can also be upgraded to pipeline
quality or simply flared.
IV-40
-------
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Air Pollution Prevented
The most significant air pollution prevention impact is the elimination of direct emissions of
methane, a powerful greenhouse gas. Nearly 3.1 million metric tons of annual methane emissions
could be avoided by 2010 under the Enhanced Market scenario. This represents roughly 20% to 40%
of current estimated methane emissions from U.S. landfills (estimates of current emissions range from
8 to 18 million metric tons per year). Small reductions in SO2, PM, and CO2 would also occur, but net
CO and NO emissions would rise slightly.
IV-43
-------
CHAPTER V
GEOTHERMAL ELECTRICITY GENERATION
Geothermal energy is the heat contained beneath the earth's surface. This heat may be
harnessed where hot water or steam naturally percolate to the earth's surface or where human-made
wells are drilled into the earth's crust. Geothermal energy can be used directly for process or space
heat, aquaculture, or agriculture; or it can be used to generate electricity.
RESOURCE BASE
Resource Base. Accessible and Reserves
Geothermal resources fall into four categories: hydrothermal, geopressured brine, hot dry rock,
and magma Hydrothermal systems are vapor- or liquid-dominated with water temperatures ranging
from 90-360 degrees Celsius (°C). Geopressured brines are high temperature (usually between 100
and 200 °C) salt water reserves containing dissolved methane, which are found at depths of
approximately 10,000-30,000 feet in permeable sandstone. Hot dry rock (HDR) is hot water-free rock
found in natural or human-made fractures several hundred to 10,000 feet below the surface, while
magma is molten or partially molten rock within the earth's crust. Hydrothermal and geopressured
brine resources carry heat to the surface in liquids that originate in the reservoir. HDR and magma
energy would be harnessed by injecting water at high pressure through a well, forcing the water or
steam through man-made cracks into a second well and then to the earth's surface for energy
conversion. The water is then re-injected into the first well; additional water must be added to make
up for losses below ground.
Estimates of the availability of geothermal resources vary widely. Figure V-1 shows a pyramid
breakdown of geothermal resources with estimates of total resource potentials. Only hydrothermal
resources have been exploited on a commercial basis thus far - the United States Geological Survey
(USGS) estimates available domestic hydrothermal resources above 90 °C to be 2400 quads - 400
quads identified, 2000 quads undiscovered (compared to 1988 U.S. electricity consumption of 29
quads of primary energy).1 These high-temperature hydrothermal resources represent a small
fraction of the total estimated geothermal resource base.
1 United States Geological Survey Circular 790, quoted in the U.S. Geothermal Energy R&D Program Summary,
U.S. Dept. of Energy, 1988, p. 2.
V-1
-------
FIGURE V -1
Pyramid Breakdown of Geothermal Resources
Geothermal
Advanced
Resources
Hydrothermal
(to 3 km)
— 44,000 Q
High Temperature
Vapor Dominated
Systems (>150'C)
—500Q
(3 to 10 km)
70,000 Q
High Temperature
Liquid Dominated
Systems (>150*C)
—4300Q
Geopressured
GeotnermaK
(to 6.35 Km)
Q
Intermediate
Temperature
System (90-150 tJ)
~4900 Q
Intruding HDR Resources
-{3to10l
-------
The Meridian Corporation report defines geothermal energy resources more broadly than does
the USGS.2 Meridian defines geothermal resources as the amount of thermal energy above 80°C and
at depths less than 6 kilometers (km), plus hydrothermal resources over 40 °C to a depth of 3.2
kilometers in areas where the temperature gradient is at least 25 °C/km.3 The total resource excludes
geothermal energy reservoirs in the National Parks, because legislation bars energy development
there. By these criteria, the geothermal resource in the U.S. is over 1.5 million quads, over 99% of
which comes from hydrothermal resources.
Meridian Corporation considers the following geothermal resources accessible: hydrothermal
resources above 80 °C to a depth of 6 km; on-shore geopressured resources over 50 °C to a depth of
6 km, excluding the dissolved natural gas; heat at temperatures over 80 °C which results from the
normal temperature gradient, and hot dry rock and magmatic energy to a depth of 6 km. Using this
definition. Meridian calculates the accessible geothermal resource at 23,000 quads, of which 98% is in
the form of hydrothermal resources. The economic subset of the accessible reserves comprises the
hydrothermal resources over 150 °C and at depths of less than 3 km, which is estimated at 250
quads.
Technically, geothermal is not a 'renewable* energy source, but because the resource is so
extensive, it is considered essentially unlimited. Some geothermal reservoirs do in fact recharge
themselves with liquid and heat, and are thus truly renewable. However, pressure in certain
geothermal systems decreases with use. For example, the Geysers geothermal field in northern
California has experienced a decrease in pressure over time, resulting in a loss in energy production
ability.4 Tests are currently underway to determine a predictable level of decline in well pressure in
geopressured and hot dry rock resources.
Geographic Distribution
Figure V-2 shows the known and potential U.S. hydrothermal and geopressured resources.
Hydrothermal reservoirs are located primarily in the western part of the U.S., with the most easily
accessible high-temperature resources in California, Nevada, and Utah. The five states reporting
2 Characterization of U.S. Energy Resources and Reserves, prepared for the U.S. Department of Energy by
Meridian Corporation. This report does not distinguish between geothermal resources as a whole and geothermal
resources sufficient to generate electricity Geothermal electric resources are significantly less than the amounts
cited in this report.
3 Temperature gradient is the measure of how quickly temperature rises with depth.
4 Geothermal Progress Monitor, December 1989. pp 23-24.
V-3
-------
FIGURE V - 2
Known and Potential Geothermal Resources
Temperature above 90°C (194°F)
Temperature below 90°C (194°F)
~?) Geopressured resources
Source: Geothermal Energy Program Summary, Volume 1: Overview, Fiscal Year 1989, U.S.
Department of Energy, January 1990.
V-4
-------
geothermal electricity production in 1989 were: California, Nevada, Utah, Hawaii and New Mexico.
Most of the untapped hydrothermal resources also occur in these states, but these resources are
frequently remote, making transmission cost and access a significant but not insurmountable issue.
Geothermal energy development in other regions depends on how quickly technologies
develop to exploit non-hydrothermal resources. If commercial technology emerges to utilize
geopressured brine resources, development could extend into Texas and Louisiana; potential
geopressured resources also exist off the Gulf Coast of these states.
Technology utilizing hot dry rock could extend geothermal development into the Northeast and
North Central states. Figure V-3 shows the regional potential for HDR based on temperature
gradients. Because the technology of HDR is still in the experimental stage, it is unreasonable to
forecast costs of HDR electricity, but the least expensive electricity will probably come from the areas
with the greatest temperature gradients. The geographic distribution of potential magma resources is
only speculative at this point, but prospects are probably best in the western portion of the U.S.
CONVERSION TO ELECTRICITY
Existing Technologies
The three components of a geothermal system are: (1) the production well; (2) the energy
conversion system; and in many systems, (3) the injection well. These are shown on Figure V-4. Four
types of electricity generating technologies have been developed to exploit geothermal resources.
Their design is based on the temperature and pressure characteristics of the geothermal fluids: (1)
dry-steam plants use high-temperature vapor-dominated resources to drive a turbine which generates
electricity; (2) flash plants tap high-temperature liquid-dominated resources; as the pressure
decreases during the flow to the surface, part of the water vaporizes into steam (called flashing"),
which is separated at the surface to drive the turbine; (3) binary cycle plants extract useable energy
from lower temperature liquid resources by passing the geothermal fluid through a heat exchanger,
which transfers energy to a separate "working fluid1 loop (with a lower boiling point than water) that
powers the turbine; and, (4) hybrid plants employ fossil or biomass fuels to raise the temperature of a
geothermal brine before transferring it into heat exchangers.5 Figure V-5 shows schematic diagrams
of flash and binary cycle geothermal conversion plants. Binary conversion technology will also be
5 For a brief description of geothermal technologies see the U.S. DOE "Geothermal Energy Program Summary,"
1988.
V-5
-------
l
in
5
13
C\J
CM
CO
IB
o
o;
o>
o
O)
CD
o
-------
FIGURE V - 4
Components of a Geothermal System
Geoscience
r Discovery
I
r Geological modeling
*
f^- Numerical modeling
Conversion
•Sensors
Well drilling
and completion
^660-13,100 ft
Geothermal power project components
Source: Geothermal Energy Program Summary, Volume 1: Overview, Fiscal Year 1989, U.S.
Department of Energy, January 1990.
V-7
-------
FIGURE V - 5
Schematic of Flash and Binary Cycle Geothermal Plants
Rash Turbine
Separator Generator
Cooling Tower
From
Production
Wells
Condenser
Flash steam technology
Turbine
Generator
Cooling Tower
Heat Exchanger
From
Production.
Wells
Makeup Water
Bmarv technology
Source: Geothermal Energy Program Summary, Volume t: Overview, Fiscal Year 1989, U.S.
Department of Energy, January 1990.
V-8
-------
used to generate power from geopressured brines, hot dry rock, and magma resources. Figure V-6
shows the water injection and steam production well configuration of an HDR plant.
Resources Recovered
Installed geothermal capacity of 2800 MW produced about 23,100 GWh of electricity in 1990.
All of the generation comes from hydrothermal resources. Dry steam plants at the Geysers in
California produced roughly two thirds of the electricity, double flash hot water plants produced about
one fourth, and binary and single flash hot water plants made up the remaining 10%.
Current Economics
Geothermal project construction time is on average 22 to 28 months, including drilling and
installation of production wells, injection wells, and piping; and construction of steam and/or brine
handling equipment.6 The construction time on the actual power plant is generally 6-24 months,
depending on size and location. For instance, a recent 20 MW plant in East Mesa, California was
brought on-line only seven months after construction began. Generally, however, the process of
obtaining permits, securing financing, and completing construction takes about 36-52 months.
Geothermal operating costs and efficiencies are directly related to the temperature of the
resource, and site-specific characteristics cannot always be easily compared. In general, the higher
temperature resources will be the most economic to develop. Other factors, including the depth of the
resource and the flow rate affect the costs of the system. Representative costs and performance of
current hydrothermal systems are shown on Table V-1. However, these numbers should not be used
to compare the relative merits of each type of conversion technology. The cost of exploiting
geopressured brine resources are speculative at this point, and since such resources provide multiple
products (heat, pressure, and methane) the cost of electricity generation is difficult to calculate
separately. The cost of hot dry rock development will depend highly on both the exploration and
drilling expenses and conversion equipment cost.
When good geothermal sites are far from existing transmission systems, lines must be
extended to access the power from these sites, and the proximity of the resources to the demand for
power or "load center will affect generation costs. Building transmission lines to geothermal sites
adds to the capital cost of geothermal development. The costs of high power transmission lines
depend on terrain and design capacity, but range between $100,000 and $500,000 per mile of line
6 California Energy Commission, Energy Technology Status fleport, 1988.
V-9
-------
FIGURE V - 6
Water Injection and Steam Production Well Configuration
Sediments
and/or
Volcanics
Low-Permeaoilitv
Crystalline
Basement Rocks
''/ 3 10 km Depth
Hot dry rock geothermal system concept for low-permeability formations
Source: Geothermal Energy Program Summary, Volume 1: Overview, Fiscal Year 1989, U.S.
Department of Energy, January 1990.
V- 10
-------
TABLE V - 1
REPRESENTATIVE HYDROTHERMAL CONVERSION COSTS9
Resource Temperature (°C)
First Law Efficiency13 (%)
Second Law Efficiency0 (%)
Wellfield Development ($/KW)
Installed Capital Cost ($/KW)
Fixed O&M ($/KW/year)
Variable O&M (c/kWh)
Capacity Factor (%)
Levelized Cost (C/kWh)
DRY STEAM
PLANT
>175
15
50
550
1550
30-40
0.3
90
3-4
FLASH PLANT
>150
10
35-40
550
1550
60
0.3
90
3-4
BINARY PLANT
>90
11 - 14
40-50
660
1860
60
0.6
90
4-6
Sources: Based on "Geothermal Resources,' Northwest Power Planning Council staff paper 89-
36, and information provided by Greg Mines, Idaho National Engineering Laboratory.
8 Values can vary widely depending on a number of factors, including resource quality.
b Fraction of energy output to heat transfer. Technologies are rated for a similar resource
temperature.
c Fraction of available energy (temperature differential between the resource and the cooling fluid)
converted to work. Technologies are rated for similar resource temperature.
required to transport geothermal electricity.7 These costs add roughly $80/kW for a 100 mile line. In
light of the high cost and various obstacles to siting and building transmission lines in the U.S.,
transmission could potentially impede geothermal development. Even if geothermal resources are
close to transmission lines, remote generation may incur moderate transmission and distribution (T&D)
losses.
7 See "Geothermal Resources" Northwest Power Planning Council Staff Issue Paper, October, 1989, p 27
($110,000 per mile for a 115 kilovolt line that could serve a 150 MW power plant); and Power Plays, by Susan
Williams and Kevin Porter, Investor Responsibility Resource Center, 1989, p. 170, ($520,000 per mile for a 230
kilovolt line that serves 600 MW of capacity).
V-11
-------
EMERGING CONVERSION TECHNOLOGIES
Efficiency/Performance
Further hydrothermal development will occur in California as the economics of geothermal
energy improve. DOE expects that most hydrothermal reservoirs in the western U.S. have been
identified; developing these resources will depend on reducing the risks of exploiting them.
Geopressured brines and HDR resources will probably be developed in the West after available
hydrothermal resources. Technologies to tap magma are speculative now, but would offer a
potentially enormous base-load energy source (initially) in the western regions of the country.
The long-term reliability of geothermal resources will play an essential role in determining the
market prospects for eventual development. There exist numerous examples of significant resource
degradation over relatively short time frames (5-15 years).8 The degree to which geothermal
resources might recharge themselves is unclear and depends on the type of geothermal field involved.
In the case of the Geysers, a vapor-dominated reservoir which has been producing electricity since
1960, neither external water nor water from depth has significantly recharged the reservoir. Long-term
flow tests are currently underway or are planned in California and Texas to examine the performance
of hydrothermal and geopressured resources respectively, under base-load conditions. With proper
well management techniques, including variations in well locations and depths; maximized production
rates and methods; fluid injection locations and rates; and production/injection control strategy,
scientists are confident that these resources will offer stable base-load energy supplies for 20 to 30
years. Verification of resource dependability is required to decrease risks for energy companies to
expand geothermal development.
Costs
As shown in Table V-2, costs of electncity are projected to drop slightly for hydrothermal, the
most established technology, and most precipitously for magma, the least developed one.
Potential Technology and Multiple Pathways
The primary technological constraints inhibiting development of geothermal resources include
the risk associated with exploration, specifically identification of well sites, verification of size and
performance of the reservoir, and maintenance of well integrity. Improvements in fluid production (the
ability to extract geothermal fluids for energy conversion) from all geothermal resources will include:
8See for example, Michael A. Grant era/ Geothermal Reservoir Engineering, pp. 211, 151-158, 218-219.
V- 12
-------
TABLE V - 2
PROJECTED COSTS OF GEOTHERMAL ELECTRICITY
1989
Hydrothermal
Geopressured
Hot Dry Rock
Magma
2000
Hydrothermal
Geopressured
Hot Dry Rock
Magma
2010
Hydrothermal
Geopressured
Hot Dry Rock
Magma
Capital Cost
($1988/KW)
BAU
1800
3200
2800
8300
1700
2700
2500
6100
1700
2200
2300
4600
R.D&D
1800
3200
2800
8300
1600
2600
2200
5100
1500
2100
1800
2600
O&M
(C/kWh)
BAU
1.8
2.9
2.5
10.0
1.8
2.6
2.3
8.0
1.7
2.4
2.1
6.0
R.D&D
1.8
2.9
2.5
10.0
1.8
2.4
2.0
5.0
1.5
2.1
1.6
4.0
Levelized Cost
(C/kWh)
BAU
4.4
7.5
6.5
21.9
4.2
6.5
5.9
16.8
4.1
5.6
5.4
12.6
R.D&D
4.4
7.5
6.5
21.9
4.1
6.1
5.2
12.3
3.7
5.1
4.2
7.7
Source: The Potential of Renewable Energy: An Interlaboratory White Paper, March 1990.
(1) optimizing drilling techniques by upgrading drill bits, downhole instrumentation, downhole motors
and properties of drilling fluids; and (2) improving reservoir management.
Conversion of hydrothermal resources to electricity has been commercial since 1960 in the
U.S., and although the technologies are relatively mature, increases in conversion efficiencies are still
possible in the future. Improvements in conversion technologies such as heat exchangers in binary
plants will also increase energy production efficiency. Other improvements in geothermal technology
V-13
-------
include computer modeling of reservoir well behavior, optimization of injection well scheduling,
prediction and elimination of scaling, and waste treatment biotechnology to reduce waste problems.9
The Geothermal Division of DOE currently supports R&D efforts into all phases of geothermal
development. Further geothermal development will focus on increased exploration of hydrothermal
resources which have been generally identified, and on the technical potential for exploiting currently
uneconomic or inaccessible resources such as geopressured brines, hot dry rock, and magma.
Hydrothermal Resources. Although hydrothermal is the most mature of the geothermal technologies,
further technology development is required to achieve the full potential of the resource. The
Department of Energy (DOE) has broken its geothermal research program into four categories:
reservoir technology; hard rock penetration; conversion technology; and industrialization.10
• Reservoir Technology. The goal of research on reservoir technology is to improve
geothermal energy utilization by developing and testing methods to more effectively
locate, develop, and utilize hydrothermal resources. Research on reservoir technology
takes three paths: 1) reservoir analysis, which will develop tools for determining
reservoir characteristics and performance; 2) brine injection technology research,
which will assess effective and environmentally acceptable injection systems; and 3)
exploration technology designed to locate and characterize geothermal resources.
The Geothermal Technology Organization, a cooperative research agreement
coordinated by DOE and industry representatives, is involved in these three areas of
research.
• Hard Rock Penetration. Hard rock penetration research seeks to reduce the cost of
drilling in "hostile* environments through development of three areas: 1) lost circulation
control, which targets technologies for detecting and characterizing loss zones and
then mitigating their effects; 2) rock penetration mechanics; and 3) instrumentation
which can increase well siting accuracy at a reduced cost. The Geothermal Drilling
Organization, a cooperative research program with industry, plays an active role in
these research areas.
9 'DOE Research and Development for the Geothermal Marketplace," Proceedings of the Geothermal Program
Review VII. March 21-23, 1989.
10 Kenneth Taylor, 'An organized effort to develop the hydrothermal energy resources," Proceedings of the
Geothermal Program Review VII, March 21-23, 1989, p 25.
V-14
-------
• Energy Conversion. Energy conversion technology research is broken into three
projects, all aimed at increasing the efficiency and economics of resource conversion:
1) heat cycle research; 2) material development; and, 3) advanced brine chemistry.
Second generation binary plant designs will improve the energy conversion potentials
of moderate temperature hydrothermal and geopressured resources. Since
geopressured brines, hot dry rock, and magma resources all require binary cycle
conversion systems, improvements in hydrothermal binary systems will also greatly
facilitate the advancement of other resources as well. Advances in hybrid power plant
design may also permit commercialization of low to moderate temperature geothermal
resources.
• Industrialization. Industrialization research is intended to promote the use of
geothermal energy throughout the U.S. and the world. This is currently achieved
through joint government/universtty/industry programs in Alaska, Hawaii, Idaho,
Nevada, New Mexico, North Dakota, Utah, Washington, Wyoming, and elsewhere.
State coupled grants, one program within the industrialization efforts, distributes funds
to organizations to study aspects of geothermal energy that are not being studied by
industry.
Geopressured Brines. Current research on geopressured brines is concentrated in three areas: well
operations, geoscience and engineering support, and energy conversion.11 Long-term resource
management experiments have been conducted by DOE at the Pleasant Bayou wells in Brazoria
County, Texas. DOE programs focus primarily on demonstrating of electricity generation potential
from geopressured resources, and operating test wells over varied conditions to obtain data useful for
future commercial ventures.12 DOE goals for 1989 included: proof of long-term injectability of spent
brine; minimization of fluid production expenses; development of automated operations; and,
development of modified scale inhibitor treatment procedures.
Hot Dry Rock Research in hot dry rock systems focuses on resource evaluation, and exploration
techniques aimed at more effectively and efficientry locating high temperature resources in
11 Kenneth Taylor, The Development of the Geopressured Resource: A Status Report," Proceedings of the
Geothermal Program Review VII, March 21-23, 1989. pp.99-101.
12 Dr. B.A. Eaton, et. al., 'Pleasant Bayou Operations Brazoria County, Texas," Proceedings of the Geothermal
Program Review VII, March 21-23. 1989, pp.103-108.
V-15
-------
underground rock fracture systems.13 Hydraulic fracturing experiments have been conducted in
deep wells to advance understanding of human-made fractures. Other tests are currently underway at
Fenton Hill, New Mexico including geochemistry and tracer studies, microseismic response analysis,
water requirements and flow impedance tests. A long-term flow test is to be conducted by Los
Alamos National Laboratories in Fenton Hill, New Mexico to determine the viability and economics of
HDR resources.t4 Resevoir management issues will be explored at Fenton Hill. Exploration
techniques for locating fractures with HDR potential (such as deep seismic surveys, acoustical
telemetry, and radar fracture mapping) must also be improved to decrease the risks of developing
these systems.
Magma. Magma research is still in the analytical stages; key issues include cheaper and improved
drilling techniques as well as better understanding of reservoir dynamics.15 DOE activities in this
area are currently on hold, but may focus on drilling and evaluating a deep exploratory well in Long
Valley, New Mexico and studies at the Kilauea Iki lava lake in Hawaii.
MARKET ASSESSMENT
Estimates of future geothermal electric technology penetration depend on the rate of
development of exploration and drilling methods and conversion technologies. Table V-3 shows the
DOE/SERI and EPA scenarios, and Tables V-4 and V-5 show cost and air pollution prevention results
of the geothermal market analysis. The EPA Base Case is identical to the DOE/SERI BALI scenario.
The Enhanced Market scenario assumes that policies are put into place to encourage geothermal
development: under these policies, almost 20,000 MW of capacity and 157,000 GWh of generation
can be obtained from geothermal electric development by 2010. The technology breakout of this
scenario includes: 16,120 MW of capacity and 127,000 GWh of generation from hydrothermal
resources, 990 MW of capacity and 7,800 GWh of generation from geopressured brines, and 2,845
MW of capacity and 22,400 GWh of generation from hot dry rock systems. No development from
magma resources is assumed.
13 Michael Berger and Robert Hendron, 'Hot Dry Rock Overview at Los Alamos.* Proceedings of the
Geothermal Program Review VII. March 21-23, 1989, pp. 147-151.
14 George Tennyson. Jr. "Hot Dry Rock Research Program Objectives Session: Introduction," Beyond Goals
and Objectives: Proceedings of the Geothermal Program Review VI, 1988, p.111,
15 "DOE Research and Development for the Geothermal Marketplace,' Proceedings of the Geothermal Program
Review VII. 1989. pp.127-131. James Dunn, 'Magma Energy Overview and Status Report.1
V-16
-------
TABLE V - 3
GEOTHERMAL SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
3,800
5,200
5,000
3,800
8,200
Generation
2000
(GWh)
30,200
41,100
39,100
30,200
61,400
Capacity
2010
(MW)
6,600
11,300
8,700
6,600
19,900
Generation
2010
(GWh)
52,000
89,400
68,200
52,000
157,000
1990: 2,800 23,100
Estimates of regional generation are based on resource availability. Hydrothermal resources
are available only in the Western U.S. (including Hawaii). Geopressurized brines are accessible in the
West and the Gulf states of Texas and Louisiana, and hot dry rock technologies could extend
geothermal development into the Northeast and North Central states.
Costs
Where available, geothermal resources could supply relatively inexpensive electric generation.
In the Base Case, geothermal generation costs average 4.5 c/kWh in 2000, and 4.4 C/kWh by 2010.
The hydrothermal resources in the West provide the least expensive generation, at 4.2 C/kWh in 2000
and 4.1 c/kWh in 2000, while small amounts of geopressured brine generation in the Southwest is
more expensive, at 6.5 c/kWh in 2000 and 5.5 c/kWh in 2010. Because geothermal generation can
fully displace conventional baseload fossil capacity, avoided costs average 4.7 0/kWh in 2000 and 7.2
C/kWh in 2010, making geothermal 2.8 c/kWh less expensive than fossil fuel generation by 2010.
Geothermal costs in the Enhanced Market scenario drop as a result of additional RD&D: in 2000,
geothermal costs average 4.1 c/kWh, falling to 4.0 c/kWh in 2010, when geothermal is 2.9 0/kWh
cheaper than fossil fuel generation. As a result of HDR penetration in the Enhanced Market scenario,
geothermal generation is also more geographically dispersed.
V-17
-------
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Air Pollution Prevented
The amount of geothermal generation that could be developed in the Enhanced Market
scenario would provide significant emission reductions. However, because geothermal resources are
located primarily in California and the Southwest (where gas-fired generation is common), emission
reduction per kWh generated is lower than most renewable resources by 2010 (see Table III-6 in
Chapter III). In the Enhanced Market scenario, geothermal electric generation could prevent almost
390,000 metric tons of NOX emissions by 2010, and could reduce SO2 by 225,000 metric tons per year
(or generate an equivalent amount of allowances). Over 90 million tons of CO2 emissions could also
be eliminated from the electricity supply sector. These emission reductions are relatively modest
compared to other renewables, but, unlike most other renewables, these emission reductions would
occur at negative cost.
V-20
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CHAPTER VI
CONVENTIONAL HYDROPOWER
Hydropower has been a significant energy source for many years due to the extensive
network of rivers throughout the United States. Nearly 71,300 MW of conventional hydroelectric
capacity had been developed by 1990, and in a good year hydro can generate nearly 14% of U.S.
electricity. Table VI-1 displays the developed conventional hydroelectric capacity in the U.S. by region
and facility type. Of all renewable resources, hydropower contributes the most to U.S. electricity
supply, and much potential still remains undeveloped. However, the environmental impacts of
hydropower development and operation - on aquatic and terrestrial ecosystems, fish populations,
wildlife habitats, and on certain types of recreation -- are becoming increasingly regulated by state
and federal laws. The result is that hydropower development has been slowed, and possibly halted,
in the last few years. However, reductions in airborne pollutants and greenhouse gases are not
generally taken into account when assessing the benefits of hydroelectric power.
RESOURCE BASE
The total resource base for hydropower consists of all the potential energy contained in
precipitation falling on the United States as it flows to sea level, adjusted for evaporation and
consumption. This total is estimated to be roughly 30 quads per year.1 Because of technical
constraints and environmental concerns, only a small portion of this potential is currently accessible
for conversion to electricity; DOE estimates that the potential from hydropower at new and existing
sites in the U.S. is slightly over 5 quads per year. The Meridian report counts approximately 2 quads
as economic reserves, which represents electricity generation at existing dam sites.
Hydropower resources are available to some degree throughout the entire United States.
Development of these resources is currently concentrated in the West and Middle to South Atlantic
States. The Pacific Northwest alone accounts for 40 percent of installed hydropower capacity. This
area of the country consistently receives large amounts of precipitation, much of which falls on higher
elevations. Because water often travels great distances from its source to the sea, it is not necessary
for a particular site to experiences great amounts of precipitation in order to have hydropower
resources. Changes in elevation are important, however, because the energy used is the kinetic
energy of water in motion which results from the potential energy of water received in higher
1 Characterization of U.S. Energy Resources and Reserves, prepared for the U.S. Department of Energy by
Meridian Corporation, June 1989.
VI-1
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elevations. This explains why Florida, which experiences much rainfall but has relatively flat terrain,
has only limited hydropower resources.
CONVERSION TO ELECTRICITY
Hydroelectric power plants convert the kinetic energy of water flowing downstream into
electricity by passing the water through a hydraulic turbine. Hydroelectric projects vary along several
dimensions: the amount of water storage, hydrostatic head, turbine type, and mode of operation.
Types of Hydroelectric Projects
Hydroelectric projects are usually categorized into three types: storage, run of river, and
diversion. The geographical and hydrological characteristics of specific sites determine the
appropriate type of hydroelectric development
Storage Projects. Storage facilities use a dam to create an artificial lake from incoming stream flow.
Storage hydroelectric projects are often rated in terms of storage capacity, usually in acre-feet of water
available for power generation. A profile of a typical storage plant is shown on Figure VI-1. Storage is
typically allocated to several uses, such as flood control, water supply, irrigation, and power
generation, and the reservoir management plan dictates how much water can be passed through the
turbines at given times during the year. The larger reservoirs may contain several weeks, and even
months, of average stream flow. Table VI-2 shows the distribution of plants by storage capacity based
on a sample of 35,330 MW of hydroelectric projects.
Some storage projects (excluded from Table VI-2) feature reversible turbines that can be used
to pump water back through the penstock (the pipe or conduit that normally channels the water into
the turbine) so that the plant can be operated in pumped storage mode. Pumped storage hydro
plants capitalize on the difference between base load and peak load generating costs by using cheap
base load electricity to pump water up behind a dam or into a separate storage reservoir, and then
release it through the turbines to generate power during higher demand periods. Pure pumped
storage projects are usually separate reservoirs (either high valleys or excavated ponds) that are not
replenished by streamflow. Other than collected runoff, the water contained in these reservoirs has all
been pumped uphill.
Run-of-River Projects. Run of river hydroelectric projects involve little or no water impoundment, so
natural streamflow completely determines the amount of water available for power generation. Figure
VI-2 shows a typical run of river hydroelectric project. At some projects, only a portion of the flow is
VI-3
-------
TABLE VI - 2
DISTRIBUTION OF PLANTS BY STORAGE SIZE AND HEAD
Plants by Storage Size
Uve Storage
(Days of Average
River Flow)
Less than 0.3
0.3 to 2.9
3 to 49
50 to 240
250 and over
Total Sample
No.
Plants
54
69
61
50
20
254
Percent
of Total
(21)
(27)
(24)
(20)
(8)
(100)
Total
Capacity
(MW)
6,040
11,230
7,850
6,270
3,940
35,330
Percent
of Total
(17)
(32)
(22)
(18)
(11)
(100)
Average
Plant Size
(MW)
112
163
129
125
197
139
Plants by Head
Normal Net Head
(Feet)
50 or less
50 to 100
101 to 200
201 to 500
501 to 1000
over 1000
Total Sample
No.
Plants
45
92
86
83
36
34
376
Percent
of Total
(12)
(24)
(23)
(22)
(10)
0)
(100)
Total
Capacity
(MW)
3,080
9,380
8.850
10,240
2,980
2.570
37,100
Percent
of Total
(8)
(25)
(24)
(28)
(8)
(7)
(100)
Average
Plant Size
(MW)
68
102
103
123
83
76
96
Source: Increased Efficiency of Hydroelectric Power, Electric Power Research Institute, June
1982.
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diverted to turn the turbines, while other plants employ "pondage," which is limited impoundment
intended to store enough energy (perhaps a few hours of streamflow) to shift maximum power output
to peak electric demand hours. Run-of-river plants tend to be smaller than reservoir storage projects,
although run of river projects on large rivers can produce several hundred megawatts of power.
Diversion Projects. Another type of hydroelectric project is a diversion or conduit, which is a man-
made channel or aqueduct of sufficient slope to create hydrostatic head. Some of these structures
are built solely for hydroelectric power, although many diversion projects are sited at existing irrigation
or municipal water supply conduits. Although diversions have no storage capacity, some diversion
projects are associated with reservoirs and can be operated like storage plants.
Head
Hydrostatic head is measured as the difference in elevation between the impounded and
downstream water levels. Head is usually rated under specific conditions, but actual head changes
throughout the year based on seasonal waterflows, reservoir management schedules and rules, and
electric generation. The Federal Energy Regulatory Commission (FERC) defines dams with gross
static head above 20 meters (66 feet) as high head dams, and those below as low head dams. Some
facilities attain over 1,000 feet of hydraulic head, with the highest exceeding 2,000 feet. There is no
specific correlation between head and capacity. The highest head facility (2,736 feet) is the 1.5
megawatt Upper Manti Canyon project, while the largest hydroelectric project, Grand Coulee Dam, at
6,180 megawatts, is rated at 343 feet of head. Table VI-2 shows the distribution of plants by design
head, based on a 37,100 MW sample of plants (plants over 10 MW installed by 1975).
Turbine Type
There are two basic hydraulic turbine types in widespread use: impulse turbines and reaction
turbines. Very high head facilities with low flows typically use an impulse turbine (sometimes called a
Pelton turbine) where water from the penstock is propelled against a series of buckets around the
periphery of a wheel. Lower head facilities generally have short penstocks and sometimes none at all.
Lower head facilities are more common and employ reaction turbines. These are usually either
Francis turbines, which use bladed rotors similar in appearance to conventional steam turbines, or
propeller turbines. Most propeller turbines, called Kaplan turbines, have runners (the blades of the
turbine) that can be adjusted for maximum power output for a given head level. These turbines have
replaced fixed-blade propeller turbines in new installations, and predominate in projects built after the
1940s. Francis turbines are used on facilities with head between 50 and 1,000 feet, while Kaplan
turbines can be used in plants rated between 10 and 100 feet of head. Tubular turbines are ultra-
VI-7
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lowhead turbines used between 5 and 50 feet of head. Figures VI-3 through VI-5 show schematic
views of turbine types. Table VI-3 shows turbine characteristics by installation date and design head.
Operating Modes
Utilities have often used hydropower to meet baseload energy demand. In addition, the quick
power response time of hydropower generation, compared to longer start-up time for conventional
fossil fuel boilers, makes it attractive for load following (varying power output to match daily demand
patterns). Many hydroelectric plants are operated as peaking units, where stream inflows are stored
behind the dam during the night and released through the turbines during the day.
Storage projects are usually operated in peaking and load following mode. However, during
the high flow season, reservoirs often have insufficient storage to operate less than full time, and are
operated continuously or in a modified peak mode. Even when operated around the clock, many
projects do not have the turbine capacity to use all of the high season flow. In these periods, some
water must be 'spilled* without passing through the turbine, foregoing potential electricity production.
Run of river plants are typically operated as baseload capacity, running continuously when
sufficient water is available. In low seasons, however, many run of river plants operate as peaking
units, since on-peak energy is more valuable than off-peak generation, and limited storage capacity
can contain small overnight inflows. Other plants have insufficient flow during low seasons to operate
at all. Diversion projects associated with reservoirs can be operated as peaking or baseload units,
although most diversions are operated as run of river plants.
Environmental Impacts
A broad range of environmental impacts result from hydroelectric development and operation.
These include the effects of dams and diversions on surrounding land, water quality issues, recreation
opportunities, and fishery impacts. All hydroelectric projects can degrade downstream water quality
because the temperature and dissolved oxygen content of water passed through turbines is often
lower than natural streamflow. Tailrace waters (water directly exiting the turbine or spillway) can also
trap excess nitrogen from the surrounding air, excess amounts of which can be lethal to trout and
salmon. Recent spillway designs that deflect water flow can minimize nitrogen saturation. Fish are
often killed when they pass through turbines, and dams prevent migrating fish from swimming
upstream. This can significantly impede the spawning activity of anadromous fish (species that hatch
in fresh water, swim into the ocean, and return to rivers to spawn). Many anadromous fish, such as
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VI-11
-------
salmon, are important commercial and recreational species. Fish ladders and other mitigation efforts
can alleviate some of these impacts, but are expensive and not completely effective in most cases.
Storage projects have the greatest overall impacts, since the land inundated with water is lost
for wildlife and recreation, and peaking operations can seriously disrupt both upstream and
downstream river and riparian (shoreline) ecosystems. Upstream impacts are due mostly to
fluctuations in reservoir levels. Downstream impacts from peaking operation due to flow variation
include changes in water depth, temperature, and dissolved oxygen, as well as the scouring of
sediments. These impacts can reduce the abundance, diversity, and productivity of downstream
riverine species.2 Mitigation options include minimum flow requirements and the construction of a re-
regulating dam (which can also generate power) to stabilize flows further downstream. Minimum flows
are sometimes set below the minimum operational rate of the turbine, and are therefore spilled without
producing electricity. Even when minimum flows can be passed through the turbine during the night,
the value of energy is typically much lower than daytime generation. Diversions, which can be several
miles in length, can reduce or cease stream flows when they divert water from natural streambeds.
Not all impacts are negative. Flood control is an important function of many dams. Some
storage projects create lakes large enough for boating and other forms of recreation. Regulated flows
on many rivers can in some cases improve the quality of Whitewater recreation, although many
Whitewater enthusiasts remain opposed to controlling or regulating natural flows.
Mitigation technologies must be developed to maximize output given strict environmental
constraints. At present, solutions to environmental concerns are applied on a case-by-case basis.
While this reflects the uniqueness of hydropower sites to some degree, it also reflects the state of the
knowledge regarding mitigation options. At present, only private R&D efforts are being pursued.
Additional government research support could help private developers examine a wider range of
options and approaches. However, DOE last funded research into small hydro systems in fiscal year
1987.
Resources Recovered and Supply Characteristics
As shown in Table VI-1, approximately 71 thousand MW of hydropower capacity has been
installed in the U.S.; storage projects account for over two-thirds of the total capacity. Average
generation from all hydropower projects totals just under 300 billion kWh. However, actual
2 See Robert M. Cushman, "Review of Ecological Effects of Rapidly Varying Flows Downstream for
Hydroelectric Facilities,' North American Journal of Fisheries Management 5:330-339, 1985.
VI-12
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hydropower output in the U.S. can vary by as much as 25% in any given year due to rainfall and
temperature conditions. The record year for hydroelectric output was 1983, when 371 billion kWh was
generated; during the drought year 1988 hydropower provided only 223 billion kWh.
Hydroelectric operation is project specific, governed by capacity, state and federal water
allocation rules, climate, utility system characteristics, and other factors. Hydropower, while
dispatchable, is not always "firm." Unlike other technologies that are limited by installed capacity,
hydroelectric production is often limited by the potential energy stored in the reservoir or watershed.
Drought can reduce the availability and power output of a hydropower system, and hydropower
output is strongly seasonal in many areas. During 1988, for example, hydropower generation was
significantly curtailed during the summer months (as was output from several fossil and nuclear plants
that rely on cooling waters.) Moreover, other claims on water resources -- irrigation, flood control,
stream flow for navigation, recreation, and wildlife - can limit the availability of hydropower during
certain times of the year.
The output of hydroelectric plants varies with seasonal rainfall and snowmelt, and even
extensive reservoir systems cannot store or otherwise smooth out all seasonal loadings. Nationally,
hydroelectric power is usually lowest in October or November, but fall rains quickly provide the peak
output in January. Another peak occurs around May, due to spring rains and snowmelt. But these
patterns vary by region: the peak flow period of the Columbia River in Oregon, for example, occurs
between April and October. While the reservoir system has altered these flows, it can store only 40%
of the spring and summer runoff, and some energy is lost through spill. Since electric loads in the
Pacific Northwest are highest in winter, some of the surplus generation is sold to meet summertime
peak load in California.3
Utilities operate hydropower to meet base, intermediate, and peak loads, subject to project
type (i.e. run of river or storage), water availability, and energy value criteria. Although definitive
national data on seasonal plant availability do not exist, hydroelectric plant factors average 48%.4
Run of river capacity attains an average plant factor of 57% (for average conditions), diversion projects
operate at 52% plant factors, while storage projects operate at 45% plant factors.
1989.
3 See "Better Use of the Hydropower System" Staff Issue Paper, Northwest Power Planning Council, October,
Plant factor is defined by FERC as the ratio of the average load on the plant for a given period of time
considered to the aggregate rating of all the generating equipment installed in the plant. Thus, plant factor is the
same as capacity factor.
VI-13
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Current Economics
In 1989, electricity prices in the U.S. averaged 7 0/kWh.5 Hydroelectricrty accounted for 10%
of U.S. electricity generation that year. In contrast, in the Northwest region, where over 80% of
electricity comes from hydropower, prices averaged 4 c/kWh.6 Electricity produced by currently
operating hydroelectric plants costs approximately half that of electricity produced by conventional
fossil plants. However, some of the federally-owned dams have been financed on extremely attractive
terms, and electricity prices may not reflect the true cost of providing hydropower from existing dams.
Since it is unlikely that a significant amount of new dam development will occur, the future
costs of hydropower will be comprised of operating and maintenance costs and the costs of
retrofitting and upgrading existing dams that either lack generators or have generators that operate
below state-of-the-art efficiencies. These costs are discussed in a latter section.
HYDROELECTRIC EXPANSION OPTIONS
Hydroelectric power generation is considered a mature technology, which is demonstrated by
the lack of significant emerging conversion technologies. Thus, while the potential for expanding
hydropower is traditionally identified with constructing new dams or augmenting existing power
generation facilities, other methods of increasing hydropower output have been the focus of recent
attention. Only about 3% of the over 60,000 dams in the U.S. are actually used to generate power,
and many of these sites have retired generation facilities. These sites represent power generation
potential with less environmental impact than new construction. The Federal Energy Regulatory
Commission (FERC) estimates that between 25 and 30 GW of conventional capacity could be
developed at existing dams. Areas with the greatest potential for development include the West and
the Middle to South Atlantic states. In addition, upgrading existing turbines and generators, and
improving operating techniques hold promise for augmenting generation from existing hydroelectric
facilities. The various options are discussed below.
Annual Outlook for U.S. Electric Power 1990: Projections Through 2010. Energy Information Administration,
Department of Energy, June 14, 1990
6 The Bonneville Power Administration currently supplies priority firm wholesale electricity from hydropower at
2.33 c/kWh. FERC approved this price and deemed it sufficient to cover costs. Conversation with Roger Seifert,
Bonneville Power Administration, April 16, 1991.
VI-14
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New Developments
Dam and powerhouse construction at river sites constitute new development. These projects
are typically very capital intensive and contentious. Obtaining a license from FERC represents a
substantial hurdle, especially for new projects that would significantly alter the natural streamflow.
Most industry observers agree that the era of large hydroelectric project development in this country is
over, and many remain pessimistic about the state of new development at smaller sites.
Power Existing Dams
Most of the dams in the U.S. were not originally designed for power generation, but were built
for flood control, water supply, navigation, or other water management reasons. Many of these could
be retrofitted with turbines. FERC has identified potential projects at non-power dams totalling nearly
19,900 megawatts of capacity which could supply 56,300 gigawatt hours per year assuming average
conditions. Owing to the types of structures available, most of this capacity -- over 11,000 MW -- is
classified as run of river. Nearly 7,300 MW of reservoir storage projects could be developed, with
existing diversions accounting for about 1,600 MW. Table VI-4 shows the breakdown of these projects
by region and type.
Although the FERC database is generally considered definitive, it may not be complete for all
regions. For example, a 1981 DOE report identified 2,600 MW of potential hydropower development at
existing Corps of Engineers navigation and flood control dams located in the Midwest.7 Many of
these potential sites are not listed in the FERC database as either developed, undeveloped, or under
construction. While FERC may have evaluated the sites as infeasible by its own criteria, it is possible
that some development potential is not reflected in the FERC data. On the other hand, because of
water quality impacts, FERC has denied hydropower license applications for retrofitting dams in this
region. The feasibility and costs of developing all of the potential sites are not known.
Redevelopment and Expansion
Existing generation sites may enhance power output by raising the dam to create larger
impoundments, replacing older turbines built to capture only a portion of the available energy, or by
adding new turbines to capture spill in high-head conditions or to extend operation into low-head
conditions. A significant portion of existing capacity includes the gains achieved at expanded and
redeveloped sites; for example, both Grand Coulee and Hoover dam projects were expanded in the
7 See Power Marketing in the Great Lakes Area, U.S. Department of Energy, August 1981.
VI-15
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1980s. FERC has identified potential expansion opportunities at existing power generation sites
totalling over 6,500 megawatts of capacity that could provide 15,400 gigawatt hours of generation
annually. Table VI-5 shows the potential capacity at developed power dams by region and type.
Two studies performed in the early 1980s identified redevelopment potential. The Army Corps
of Engineers concluded that expanding existing powerhouses could increase national hydroelectric
output by roughly 11%, mostly through additional spill capture, while an Electric Power Research
Institute (EPRI) study of large hydroelectric facilities estimated that capacity could be increased by
14% by adding generating units and storage, yielding an increase in generation of 2.6%.8 FERC has
identified 243 existing hydroelectric facilities with potential for expansion, and 20 of the 174 projects
under construction as of January 1988 were expansion projects at existing facilities.9 Thus, some of
the potential identrfied in the late 1970s has probably been realized.
Raising the dam structure to create a larger impoundment and increase head requires a dam
safety assessment and could have environmental impacts that would preclude licensing. Adding or
replacing turbines, on the other hand, would probably have less adverse environmental impacts. All
redevelopment options require significant expense, although substantial gains in capacity and
(typically smaller) gains in generation will be economically justified in many cases.
Restore Retired Power Generating Stations
FERC has identrfied 3,112 retired hydro generating stations, and over two-thirds of those have
filed capacity data with FERC.10 Table VI-6 shows the capacity of these sites by region. If the
reported sites are representative of the unreported sites, almost 2,200 MW of potential capacity may
exist at retired sites. It is not clear the extent to which these sites are constrained to historic power
generating levels rf restored with modem equipment. Between 1980 and 1988, 142 retired sites were
returned to operation status, amounting to roughly 100 MW of hydroelectric capacity (assuming the
sites were representative of the FERC data).11 However, even the redevelopment of retired
8 See Potential for Increasing the Output of Existing Hydroelectric Plants, National Hydroelectric Power
Resources Study Volume IX (Washington D.C.: U S Army Corps of Engineers, July, 1981) p. 15, and Increased
Efficiency of Hydroelectric Power, (Palo Alto: Electric Power Research Institute, June 1982), page S-5.
9 Hydroelectric Power Resources of the United States: Developed and Undeveloped, (Washington D.C.:
Federal Energy Regulatory Commission, January 1, 1988), Table IX, p. xxv.
10 Figures taken from FERC computer printout "Retired Hydropower Plants in the Unites States" dated July 7,
1989.
11 Hydroelectric Power Resources of the United States: Developed and Undeveloped, (Washington D.C..
Federal Energy Regulatory Commission, January 1, 1988), p. xviii.
VI- 17
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TABLE VI - 6
RETIRED HYDROELECTRIC FACILITIES
REGION
New England
Mid Atlantic
South Atlantic
Florida
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
TOTAL
NUMBER
OF
SITES
1.472
385
194
3
435
240
34
20
149
11
53
82
3,078
SITES W/
CAPACITY
DATA
716
347
170
2
404
223
29
19
139
10
8
81
2,148
REPORTED
CAPACITY
(MW)
364
248
122
12
201
134
20
12
126
22
171
73
1,505
* SITES
MW > 1
77
64
34
2
54
30
2
5
23
1
13
20
325
# SITES
MW > 5
7
6
1
1
2
6
1
0
4
1
6
2
37
Source: Federal Energy Regulatory Commission (FERC) database, printout dated July 7, 1989.
VI- 19
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generating stations can provoke dispute. Many of these dam sites were constructed long before
environmental impacts were considered and mitigation actions were required. Many retired sites
might not be economic to restore when the costs of required studies and mitigation measures are
considered. In fact, the attention drawn to retired power generating dams during the license
application process has aroused calls for the physical removal of certain dams.
Generator and Turbine Modernization Upgrades
Hydropower operators are investing in efficiency improvements for many generator and
turbine sets, with resulting increases in energy and capacity. Both the Army Corps of Engineers study
and the EPRI study concluded that equipment uprating and improvement could expand annual
hydropower generation by about 3,700 GWh (about 1.4% of 1980 generation), and capacity by about
4,000 MW (about 6% of 1980 capacity according to EPRI). Increased generation can result from
mechanical efficiency gains as well as spill capture.
Some of this mechanical potential was realized during the 1980s, and the improvements
achieved suggest that the earlier studies may have been conservative. According to a recent industry
estimate, about 750 individual turbine units were modernized between 1980 and 1989, split equally
among runner replacements, rehabilitation performed by manufacturers, and rehabilitation performed
by owners (rehabilitation will typically include a runner replacement). The runner replacements were
conducted on units where runners averaged 53 years old, and the average increase in turbine output
was an impressive 22 percent.12
Index testing and governor calibration is another modernization technique for Kaplan turbines.
The index test establishes the optimum wicket gate to turbine blade angle, which can be used to
fashion a set of mechanical cams to ensure maximum power output. Output gains of the order of 2%
to 3% are possible.
The ultimate potential of hydropower modernization is difficult to gauge. Since the activity
during the 1980s was driven by economics, most of the oldest, least efficient facilities may have
already been modernized, limiting the energy potential of subsequent projects. On the other hand,
continued refinement of techniques and equipment may allow upgrading to supply more power than
initial estimates implied, especially as the need for new utility capacity increases. As a rough estimate,
perhaps 4,000 to 6,000 MW of additional potential remains.
12 Presentation by Don Froelich, Black & Veatch Inc, at the National Hydropower Association Conference,
Washington D.C., July 16, 1990
VI-20
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Improve Operating Practices
Wide-scale adoption of new monitoring and control techniques, as well as changes in
reservoir management practices, could maximize energy production from existing developments. For
example, opportunities exist at large, multi-turbine, hydroelectric projects to enhance the combined
output of the facility by operating individual turbines in an 'optimal dispatch,' taking into account both
the available hydraulic resource and electric load. Many owners are currently investigating these
options or implementing improved operating rules.
Changes in reservoir management can increase hydropower output in some cases. Improved
coordination of multiproject reservoir systems may enhance the value of generation. Changing
reservoir regulation schedules or reallocating flood control space can increase output, although these
operational changes require prudent study and face many constraints due to the competition for water
resources and the concerns for adequate flood control. The Army Corps of Engineers study
suggested that a 1 % increase in national hydropower generation may be possible from reallocating
flood control storage, and that such actions could increase energy value by enhancing the
dependability of the capacity (convert non-firm energy to firm energy).
Modifying the operation of peaking hydropower units to more run-of-river mode would reduce
energy value, but in some cases, might also provide aggregate emission reductions in some utility
systems dominated by coal baseload plants where gas-fired turbines could provide the lost peak-load
generation. Since the peakload variation in waterflow has detrimental effects on downstream water
quality, the increased restrictions placed on hydropower operation are moving the industry in this
direction already.
Because changes in hydropower operation may be constrained by other claims on river
resources, the system implications of transferring hydropower from peak to baseload must be
evaluated from an economic and environmental perspective. One recent analysis examined the
emissions impact of altering the operation of hydropower capacity in the Los Angeles Department of
Water and Power system.13 The authors estimated that converting peak storage hydroelectric
plants to run-of-river operation would increase emissions, due to an increase in fossil-fuel plant output
for pumped storage to satisfy peak power demands, as well as technological constraints on reducing
the operation of other fossil fuel plants during low demand hours. Thus, the success of altering
13 See "Assessing the Environmental and Economic Effects of Changes in Hydro Generation on the LADWP
System." by Kenneth Henwood and David Branchcomb, paper presented to the National Hydropower Association
Conference, Washington D.C., June 17.
VI-21
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hydropower operations as an emission reduction strategy depends on the characteristics of the utility
system. For some systems, a change from peaking operation to run-of-river mode may still reduce
emissions, and growing concerns over the ecological impacts of peaking operations could stimulate
emission reductions in some circumstances.
Hydroelectric Expansion Costs
The costs of hydroelectric investment options vary substantially, from over $3,000 per kW for
new developments at some sites to less than $100 per kW for generator or turbine upgrades that yield
small gains. Since each hydroelectric project is unique, similar expansion projects display wide
variation in costs, as shown in Table VI-7, based on industry surveys. However, institutional and
regulatory constraints, rather than costs, dominate most questions of hydropower resource
development. In addition, the costs of the environmental impact studies required for licensing or
relicensing can be high, and have sometimes led potential developers to abandon a project. Recent
data indicate that the cost of studies and other administrative requirements needed to relicense a 1
MW plant averages $300,000, and can exceed $500,000, while a 10 MW plant requires nearly
$1,000,000.14 Thus, relicensing costs between $100 and $500 per kilowatt of capacity. Given
construction costs of between $1,500 and $2,500 per kilowatt, the costs of building new capacity can
now exceed $3,000/KW. Costs are unlikely to decline to any appreciably in the near future.
TABLE VI - 7
REPRESENTATIVE HYDROELECTRIC EXPANSION COSTS
OPTION
New Development
Power Existing Dam
Expand Capacity
Restore Retired Plant
Turbine Upgrade
CAPITAL COST
($/KW)
1,500 - 3,500
1,250-3,000
1,000-2.000
700- 1.500
50 - 600
VARIABLE COST
(0/KWh)
0.4 - 0.8
0.4 - 0.8
0.3 - 0.6
0.4 - 0.8
N/A
LEVELIZED COST
(C/KWh)
4.0 - 9.0
3.5 - 8.0
3.0 - 6.0
2.0 - 5.0
0.1 - 1.5
14
Figures from "The High Cost of Hydro Licensing" by Richard Hunt, Independent Energy, October 1990 based
on recent EPRI reports.
VI-22
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According to the FERC database, expansion projects at existing power dams would attain an
average plant factors of only 27%, while hydropower developments at existing non-power dams would
attain annual plant factors of 32%. In the former case, low plant factors reflect the relatively high
proportion of storage projects in the FERC assessment, as well as the limited operation of additional
turbines. Most developments at non-power dams would be operated in run of river mode. These
relatively low factors also reflect the likelihood that many of the best water resources are already
developed.
MARKET CHARACTERISTICS AND CONSTRAINTS
Ownership
The federal government owns and operates 39.5 GW of conventional and pumped storage
capacity, or 44 percent of total U.S. hydroelectric capacity (including pumped storage) of 89.1 GW.
Three agencies - The U.S. Army Corps of Engineers (ACE), the Bureau of Reclamation (BOR), and
the Tennessee Valley Authority (TVA) - account for over 99% of this capacity. TVA markets its own
power, while other federally generated power is marketed by the five other power marketing agencies
(PMAs). The largest of these, the Bonneville Power Administration, markets power from dams in the
Northwest. The institutional principles that guide investment and operation in these agencies differ
from those that govern utility planning, and reform may lead to more efficient utilization of existing
hydropower capacity.
The lack of incentives within certain Federal power authorities is a potential barrier to
hydroelectric efficiency improvements. The manner in which power is generated by these authorities
and sold by PMAs provides little incentive for implementing efficiency improvements. In order to make
the necessary investments, the generating agencies would need to request an appropriation from
Congress, and any increased revenues or profits resulting from efficiency improvements would be
realized by the PMAs, who would forfeit those to the U.S. Treasury. From the perspective of the ACE
and BOR, efficiency improvements involve an increase in their work load with no appreciable benefit in
terms of their own financial position. On the other hand, the TVA and public utilities typically have
appropriate incentives and are proceeding to implement efficiency improvements.
Municipalities and cooperatives, which are operated for the benefit of the ratepayers, own
about 19.2 GW of conventional and pump storage hydropower, or about 22 percent of U.S. capacity.
Private utilities and private non-utility ownership accounts for the remainder. Private utilities operate
28.4 GW; non-utility hydropower developers represent a small (1.3 GW), but growing segment of the
market. Under the Public Utilities Regulatory Policies Act (PURPA), non-utility developers were
VI-23
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guaranteed a market for electric power produced from small hydroelectric plants, and FERC grants a
license exemption for any project less than 1,500 KW.
Non-federal owners face the potential for competition for the FERC license. If another entity
can prove to FERC that it could operate the project more efficiently than the current owners, then
FERC can transfer the license to the contestant, forcing the current owner to sell the plant to the
licensee. This institutional arrangement has compelled many owners to examine potential
improvements. Before the passage of the Electric Consumers Protection Act of 1986 (ECPA), plants
undergoing relicensing often increased capacity and energy, sometimes gaining as much as 40%
additional capacity and 65% additional energy production. However, the increased restrictions posed
by ECPA (see below) has largely erased large gains, and has lead to reduced capacity and energy in
some cases.
Environmental and Regulatory Constraints
Hydropower development faces a barrage of environmental constraints under current law.
These range from a complete moratorium on development on federal and state designated scenic
rivers to impact studies required for the relicensing of existing hydropower facilities. Some institutional
constraints also exist, since many hydroelectric facilities are federally owned and hydropower
operation can be limited by rules, contracts, treaties, and other agreements that govern the use of
water in a reservoir system.
Electric Consumers Protection Act of 1986 (ECPA). The Electric Consumers Protection Act of 1986
(P.L 99-495) requires that hydropower licenses be issued only if the benefits of hydroelectric
generation exceed the costs, when compared on an 'equal consideration" basis. This applies to initial
license applications for new projects and to relicensing efforts at existing facilities. ECPA requires that
the power benefits be compared with non-power benefits and costs. These non-power concerns do
not generally include air emission impacts; however, a broader view of power and non-power impacts,
including avoided air emissions, are beginning to be considered in order to better fully measure the
benefits of hydropower. Considering the system-wide emission impacts of hydropower operation in
licensing or other decisions, while complex, would expand the focus from the local impacts on water
quality, fish, plant, and wildlife habitat that currently dominate the process.
The studies and assessments required by ECPA, in addition to other legislation such as the
National Environmental Policy Act and the Clean Water Act, have been a source of controversy in the
hydropower industry. The cost and time required to perform the studies have derailed some projects,
especially smaller ones. A complete assessment of plant and wildlife impacts, water quality, and
VI -24
-------
riparian ecosystems must be made. If a project is approved for licensing, it may be subject to a
variety of restrictions, such as minimum stream flow requirements for fish or recreation, dissolved
oxygen requirements, and mandatory structures to reduce fish mortality.
The majority of non-federal projects, which account for roughly half of existing conventional
capacity, will be subject to relicensing in the next 20 years. About 200 hydroelectric projects have
FERC licenses that will expire during the 1990s, with 166 licenses expiring in 1993 alone. As
displayed on Table VI-8, the combined capacity of projects subject to relicensing between 1990 and
2010 is 20,900 MW. These plants face the prospect of reduced capacity and energy owing to
additional environmental constraints such as minimum flow requirements to protect ecological
resources. Minimum flow regimes can reduce the energy for power generation and the value of
power output. These impacts are especially pronounced on large storage projects, where industry
observers anticipate output reductions up to 10 percent at some projects.
Off-UmIt Rivers. According to FERC, roughly 45.8 gigawatts of potential projects, capable of
generating 126,370 gigawatt hours annually, are precluded from development, or subject to a
moratorium while being studied, under the National Wild and Scenic Rivers Act and other laws.15
Several states and local jurisdictions have also have designated specific rivers off-limits for
hydropower development. For instance, the Northwest Power Planning Council restricted more than
44,000 miles of streams in Oregon, Washington, Idaho, and Montana from hydroelectric development.
Endangered Species Act. Recently, the Shoshone-Bannock Tribes of Idaho, along with fishing
associations and environmental groups, filed petitions with the National Marine Fisheries Service to list
five species of Northwest Salmon as endangered or threatened under the Endangered Species Act. If
these petitions are granted, and similar petitions are brought to protect species in other river basins,
river management will be significantly altered. The resulting mitigation measures could substantially
reduce hydroelectric generation at existing sites and prohibit development at others.
MARKET ASSESSMENT
The EPA hydroelectric scenarios consider expansion only at existing dam sites, including
refurbishment and upgrades, expansion of existing generating facilities, powering existing dams, and
restoring retired generation facilities. Both scenarios incorporate the potential impact of post-ECPA
relicensing decisions, which could reduce capacity, energy production, or both from existing
Hydroelectric Power Resources of the United States: Developed and Undeveloped, Federal Regulatory
Commission, January 1, 1988. p. xxvii.
VI-25
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hydropower projects. Run of river projects subject to relicensing are assumed to have capacity
reduced by 2% and energy reduced by 1%, but storage projects are assumed to lose 4% of capacity
and 2% of energy. These impacts reduce existing capacity by 70 MW between 1990 and 2000, and
reduce capacity by 690 MW over the 1990-2010 period, reflecting the concerns of industry analysts
that many projects will lose significant capacity and energy in the coming years. Table VI-9 shows
capacity and generation estimates for the EPA and DOE/SERI scenarios.
Under the EPA Base Case, conventional hydropower capacity would increase by 3,420 MW
between 1990 and 2000 (rising from 71,270 MW to 74,690) and would increase another 2,000 MW
between 2000 and 2010 (reaching 76,690 MW), an annual average growth rate of only 0.4% during
the period. Because hydropower expansion at existing dams tends to operate at lower plant factors
than existing capacity, generation would increase by 6,950 GWh between 1990 and 2000, and
increase by 13.640 GWh between 1990 and 2010, an average annual growth rate of about 0.2% over
the period.
The EPA Enhanced Market scenario portrays a more robust future for hydroelectric
development at existing dams in the U.S., spurred by increased concern over the environmental
impacts associated with fossil fuel-fired generating capacity. Additional R&D into mitigation options is
assumed to make a greater fraction of the identified potential at existing dams subject to
environmentally acceptable development. Although relicensing losses are assumed to be identical to
the Base Scenario, the Enhanced Market scenario could increase hydroelectric capacity by 10,500
MW between 1990 and 2000, and by 16,490 between 1990 and 2010, an annual average growth rate
in capacity of 1.2%. This additional capacity would provide 45,500 GWh per year under average
conditions.
The costs of hydropower expansion options are assumed the same in both EPA scenarios.
Because costs are very project specific, they should be regarded as suggestive. On the one hand,
some costs are likely to fall as a result of greater market activity in the Enhanced Market scenario, and
some streamlining of regulatory process cost is likely. On the other hand, developers will have to
undertake more difficult and challenging expansion projects. These two effects are assumed to offset
each other, keeping capital costs of each expansion option the same between the two scenarios.
The cost and air pollution prevention figures reported in Tables VI-10 and VI-11 combine the
results of separate analyses of run-of-river and storage projects (see Appendix B for separate results).
In the Base Case, over 40% of the expansion occurs in the Washington/Oregon region, 13% in
California, 10% in the Mountain region, and 9% in the Mid Atlantic region. The expansion of
hydropower is more geographically dispersed in the Enhanced Market scenario: the
VI-27
-------
TABLE VI - 9
HYDROELECTRIC SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
76,800
79,800
81,700
74,700
81,800
Generation
2000
(GWh)
331,600
333,600
339,400
305,000
324,800
Capacity
2010
(MW)
77,800
97,500
103,600
76,700
87,800
Generation
2010
(GWh)
335,500
387,200
404,800
311,700
343,500
1990: 71,300 298.000
Washington/Oregon region accounts for 23% of the increase, while seven of the remaining eleven
regions account for between 7% and 11% of the incremental generation.
Costs
Generation costs vary by region according to the assumed mix of hydroelectric projects, which
include refurbishments and upgrades, expansion of existing generating facilities, powering existing
dams, and restoring retired generation facilities.16 Hydroelectric generation costs are very
competitive with fossil fuel-fired electricity, especially for storage projects that provide peak load
power. However, because hydropower is not always firm' due to seasonal and yearly variation in
precipitation (i.e. hydropower does not receive full capacity credit in the REM), the avoided
conventional cost for hydropower generation averages about 4.3 c/kWh in 2000 and 5.1 c/kWh in
2010. Hydropower generation costs are lowest in the North Central region and highest in California,
and overall average about 5 e/kWh across the U.S. By 2010, generation from expanded hydropower
16 Incremental hydropower costs are overstated somewhat because new expansion is offset partially by
reduced generation at existing sites subject to rehcensing restrictions. The unit costs reported here reflect the
expansion costs divided by the net increase in regional generation.
VI-28
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generation would be cheaper than fossil fuel generation in the Northeast, Southwest, North Central,
and California, and would prevent air pollution at negative cost in those regions.
Air Pollution Prevented
The restricted expansion opportunities at existing sites limits the overall amounts of fossil-fuel
emissions displaced by increased hydroelectric output. However, the geographic distribution of
potential resources and generating characteristics make hydropower an effective technology for air
pollution prevention, as evidenced by relatively high emission reduction rates (per kWh) shown on
Table 111-6 in Chapter 3. The increase in hydroelectric generation between 1990 and 2010 in the
Enhanced Market scenario would reduce annual NOX emissions by 177,000 metric tons, and CO2
emissions by 42 million metric tons per year. Hydropower generation in the Enhanced Market
scenario could displace up to 270,000 metric tons of SO2 emissions per year, equivalent to generating
about 300,000 allowances.
VI-31
-------
CHAPTER VII
PHOTOVOLTAICS
Photovoltaic (PV) power uses semiconductor technology to convert sunlight directly into
electricity. The first recording of the sunlight-to-energy conversion, the photovoltaic effect, occurred in
1839 when a French physicist observed that illuminating one of two identical electrodes in a weak
conducting solution would produce voltage; in the 1870s, the photovoltaic effect was further studied in
solids such as selenium. This led to selenium photovoltaic cells with conversion efficiencies of
1% - 2% by the 1880s.1 The technology lay dormant until 1954 when Bell Laboratories made
practical silicon PV cells that reached sunlight-to-electricity conversion efficiencies from 6% to 11%; the
cost of these silicon cells was approximately $600 per watt. Not until the late 1950s, with the onset of
the space age, did extensive research and development into photovoltaics began. In their earliest
applications PV cells made from single-crystal silicon powered America's first space satellites.2
Between the late 1950s and the early 1970s, research achievements and refinements in the
manufacturing process doubled solar cell efficiencies and brought prices to under $100 per watt;
nevertheless, only two companies manufactured solar cells for commercial use in the early 1970s.
The 1973 Arab oil embargo greatly stimulated PV development activities by bringing in an infusion of
public and private research funding that provided for basic research and the development of new
products, expanded the array of PV applications, and induced the growth of the PV industry. Between
1975 and 1976, total sales of PV cells doubled, prices fell to $15 per watt, and some of the cells being
tested achieved efficiencies five times greater than that of the Bell team's original prototypes.3
Both stand-alone (non grid-connected) and central station utility (grid-connected) PV systems
have been researched. These applications hold the possibility for gigawatts worth of installation.
However, in order to realize this potential, several obstacles have to be overcome. PV systems must
continue to become more efficient, more durable, and less expensive. Photovoltaic costs have
declined from $20 per watt in 1977 to $4-$5 per watt in 1988, but costs must decline further and
efficiencies increase before PV makes significant contributions to the U.S. electricity supply. Future PV
1 American Solar Energy Society, "Assessment of Solar Energy Technologies," May 1989.
2 Solar Energy Research Institute, "Photovoltaics - Entering the 1990s," November 1989.
3 Susan Williams and Kevin Porter, investor Responsibility Resource Center, Power Plays: Profiles of America's
Independent Renewable Electricity Developers. 1989.
VII-1
-------
technology development and market penetration will depend on federal support to a greater extent
than any other renewable electric technology.
RESOURCE BASE
Base. Accessible, and Reserves
A recent study conducted by Meridian Corporation for DOE estimates the 30 year photovoltaic
energy resource at one million quads. This value, which is the same as the biomass and solar
thermal energy resource base, is the product of the average incident radiation on the surface of the
U.S., about 4.32 kWh/m2, and the proportion of the radiation which Meridian considers intense enough
to be a potentially exploitable resource, which they estimate at 70%.4 The accessible resource,
600.000 quads, is that portion of the total resource which strikes land not dedicated to forests,
cropland, parkland, wilderness area, surface water, roads, national defense and urban areas.
Because the levelized cost of PV generated electricity is currently much higher than conventional utility
electricity, the PV energy reserve is zero. This does not take into account certain niche markets -
primarily non-grid connected - where the value of PV generation justifies the high costs.5 Currently,
approximately 13 MW of installed PV capacity produced a fraction (less than one hundredth) of a
quad each year.
Geographic Distribution
Scientists have spent more than a decade studying the availability and amount of sunlight
throughout the U.S. Actual sunlight totals, adjusted for cloud cover, were measured and broken down
by location, time, and type of sunlight.6 The resulting data bases enable scientists to generate maps
of the solar resource. For example, Figure VII-1 displays how much solar radiation is available to a flat
plate PV module mounted on a fixed support structure, with the southern tilt (in degrees) equal to the
latitude of the site.
4 Characterization of U.S Energy Resources and Reserves Prepared for the U.S. Department of Energy by
Meridian Corporation, June 1989.
5 One example is the increasing use of PV by electric utilities as a DSM tool, particularly to reduce high
marginal cost peak load demand
6 See, for example, Probabilities and Extremes of Solar Radiation by Climatic Week. National Weather Service,
Fort Worth, Texas Southern Region.
VII-2
-------
FIGURE VII -1
Average Annual Global Radiation Available to a Fixed Plate
With Tilt Equal to Latitude
(100s of kWh/m2)
Source: Ken Zweibel. Harnessing Solar Power. The Photovoltaics Challenge, 1990, p. 231.
VII-3
-------
As the map indicates, PV resources are available throughout the United States. The annual
average solar energy received in the U.S. varies only by a factor of two from northern to southern
latitudes, which means that annual solar radiation received anywhere in the continental U.S. is no
more than 50% lower than that experienced in a peak location like Phoenix. Unlike solar thermal, PV
can utilize indirect (diffuse) as well as direct solar radiation, so that the PV resource is not confined to
the arid Southwest. However, the sun shines differently across the U.S., and each geographical
region is subject to the vagaries of microclimates and cloud cover.
Seasonal and Daily Variation
Figure VII-2 depicts the regional and seasonal variation of the solar resource in terms of
monthly insolation figures for Phoenix, Atlanta, Seattle, Madison and Ft. Worth.7 Based on solar
radiation and climatological data, the Southwest region of the U.S. has the most solar radiation, and
the Pacific Northwest, North Central and Northeast U.S. have the least.
Solar radiation also varies throughout the day, and the hourly variation depends on time of
year, latitude and daily weather patterns. Figure VII-3 compares the hourly insolation values on an
average sunny day in June and January for locations at 45 degrees north latitude such as Portland,
Oregon or Minneapolis.8 Because the difference between summer and winter insolation is greater at
higher latitude, the case portrayed shows the most extreme seasonal contrast experienced in the
continental U.S..
CONVERSION TO ELECTRICITY
Existing Technologies
The primary element of a photovoltaic system is the solar cell. Each solar cell has two or
more layers of dissimilar semiconductor material, between which a junction creates voltage to drive
electrons through a circuit. Solar cells are composed of different materials in various states - single
crystal, polycrystalline, and amorphous. PV cells convert light directly into electricity. When sunlight
strikes the photovoltaic cell, photons (particles of light energy) enter the cell's semiconductor material
7 Stand-Alone Photovoltaic Systems A Handbook of Recommended Design Practices. Photovoltaic Design
Assistance Center, Sandia National Laboratories. March 1990. pp. A-1 - A-42.
8 Muhammad Iqbal, An Introduction to Solar Radiation, (New York: Academic Press, 1983), p. 241. The graph
shows the power in KW/m* incident on a horizontal plane, so the area under the graph gives the daily energy
output in kWh/m2.
VII-4
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and transfer their momentum to electrons in the cell, knocking them free and forming a 'hole' in the
cell. The freed electrons travel through the semiconductors and contacts to form direct current (DC).
Figure VII-4 shows a schematic of the photovoltaic effect. PV cells require no moving parts or steam
cycle and emit no pollutants during operation. Single cells are connected in series to create a PV
module or panel, usually less than a square meter in size, which is sealed with a protective layer of
plastic or glass. Modules can be combined to create larger flat plate arrays. Larger PV systems
consist of multiple arrays that share power conditioning equipment. PV generating systems convert
the DC electricity into alternating current (AC) using a power inverter. Some energy losses occur in
this conversion, but the process is necessary if the PV power is intended for the AC utility grid. PV
systems are rated in peak Watts (Wp), denoting the PV power output when the equivalent of the sun's
energy (i.e. 1000 Watts/m2) is directly shining on the PV surface at noon on a sunny day. PV system
efficiency is measured by the percent of available solar energy that is converted into electricity, while
actual system output depends on the site's latitude, weather, and time of day.
Materials and Cell Types. PV cells are classified as crystalline thick-film or thin-film cells. The choice
between cell type depends on the trade-off between production cost and efficiency: thick-film cells
are more costly, more efficient, and have long expected lifetimes, whereas thin-film cells are cheaper,
less efficient, and may have problems with long-term stability. The majority of cells applied today are
crystalline thick-film1 cells. The cells have achieved efficiencies of 12% to 16% and have
demonstrated reliable operation. Thin-film cells offer the most potential for low-cost modules.
However, the long-term stability of thin-film cells must first be demonstrated before use of this
technology will become widespread. Demonstration projects being conducted by the Solar Energy
Research Institute (SERI), in which some thin-film materials (including copper indium diselenide) have
shown no signs of degradation after three years while others (including cadmium telluride) have
yielded mixed results, may provide the data necessary to resolve questions of long-term stability.
Materials such as silicon, copper indium diselenide. cadmium telluride, and gallium arsenide
are being used to manufacture PV cells with single crystal, polycrystalline and amorphous structures.
Silicon has been the preferred matenal because of its abundance, low cost, and attractive chemical
properties. Silicon cells now produce 80% of U.S. PV electricity. The amorphous semiconductor
structure has received increased commercial research and development focus because it allows
application in a few micron-thick film, 50-100 times thinner than wafer application of single and
polycrystalline materials. The trade-off between amorphous material and single crystal is one between
cost and efficiency: commercial amorphous modules achieve 5% - 8% efficiency but are cheaper to
manufacture than single crystal cells that average 10% -16% efficiency. Increased attention is also
being directed to multi-junction or tandem devices using amorphous silicon thin film cells in which
multiple, extremely thin, light-activated, electricity-generating junctions are layered on top of each
VII-7
-------
FIGURE VII - 4
Schematic of the Photovoltaic Effect
The Photovoltaic Effect
Suniigm
Adhesive
Ann-Relteciion
Coating
n-Tyoe
Semtconouctor
D-Tyoe
Semiconouctor
Back
Contact
Source: Photovottaks: Technical Information Guide. Solar Energy Research Institute.
U.S. Department of Energy (SERl/SP-271-2452). February 1985. p. 2.
VII-8
-------
other. Tandem cells can capture a larger portion of solar radiation than single-junction cells, as the
top cell absorbs the high-energy portion of the spectrum and allows the rest through to the cells
below. Overall tandem cell efficiencies could reach as high as 20% - 30%.
Tracking Systems. Individual PV modules are combined in configurations that include fixed flat plate
arrays, single or double-axis sun tracking flat plate arrays, and double-axis tracking sunlight
concentrator arrays. Fixed arrays do not move during the day to capture more sunlight. Single axis
trackers follow the sun's course from east to west during the day, while double axis trackers also
adjust the array for the sun's change in apparent attitude during the year. This means that the array
always points directly at the sun. The power gained from using a single axis tracker over a fixed flat
plate is realized mostly during the early morning and late afternoon, and the double axis tracker
ensures maximum power during each season. A double-axis tracker picks up as much 40% more
energy than a fixed array. The additional cost of tracking devices are often offset by greater energy
capture, although fixed plate collectors are the most economic option in many applications.
The tilt of fixed plate and single axis tracking arrays can be adjusted to maximize productivity
during a particular season and/or time of day, in order to tailor output to peak electricity demand.
Figures VII-5 and VII-6 compare the amount of solar insolation available to fixed and single axis
trackers with tilts equal to latitude-150, latitude, and latitude+15° and to a double axis tracker. In
general, a tilt equal to latitude maximizes the yearly output of a fixed or single axis tracker. A tilt of
latitude-150 maximizes summer output at a small cost to the yearly output, while a tilt of latitude+15°
maximizes winter output. A double axis tracker captures the greatest possible amount of the solar
resource during all seasons and times of day. By tilting a fixed array to the east or west, one can
receive peak output, respectively, before or after solar noon, at a small cost to total daily output.
PV concentrator modules use mirrors and lenses to concentrate the sun's light onto a small
area, reducing the number of solar cells used in the module. Replacing expensive solar cells with
optical elements made of inexpensive glass, plastic, and metal lowers costs. Costs are also reduced
because solar cells perform more efficiently in concentrated light than under normal, dispersed
sunlight, achieving efficiencies approaching forty percent in laboratory tests.9 However, since PV
concentrator modules must aim directly at the sun, they require more expensive two-axis trackers.
Current Performance of Actual Systems. The Electric Power Research Institute (EPRI) analyzed data
from 1987 and 1988 to assess the performance and supply characteristics of operational PV power
9 Photovoltaic Energy Program Summary, U.S. Dept. of Energy, Volume I: Overview Fiscal Year 1989, January
1990.
VII-9
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plants10. The plant data for 1987 included information from a 204 kW dual axis tracking
concentrator plant in Phoenix, Arizona; a 300 kW single axis tracking system in Austin, Texas; a 1000
kW dual axis tracking system at Hesperia, California; and the 2,350 kW single axis tracking
Sacramento Municipal Utility District (SMUD) plant in Sacramento County, California. The data from
1988 included information from the above plants as well as a 15 kW amorphous silicon array in
Orlando, Florida, and a 4 kW amorphous silicon array at Auburn Hills, Michigan. Daily and seasonal
operating characteristics were recorded and analyzed, along with energy output and other variables.
The generation data for the four plants surveyed in 1987 is displayed in Table VII-1.
Current Economics
As shown on Figure VII-7, PV costs have fallen significantly over the past two decades, as
efficiencies have increased. The costs of a PV system fall under the categories of module costs and
balance of system costs (BOS). Currently, module costs are roughly equivalent to BOS costs.
Module costs depend on the material used, the amount required and the process used to fabricate
the cell. Although crystalline devices are more efficient in energy conversion, they are considerably
more expensive than thin-film devices. BOS costs include: design, land, site preparation, installation,
trackers and support structure, power conditioning equipment, operation and maintenance and
storage and related costs. The costs fall roughly under the categories of area-related and power-
related. Trackers and support structure make up the majority, about 75%, of area-related BOS costs.
Current tracker costs are $85/m2 for a single axis tracker, $120/m2 for a double axis tracker and
$140/m2 for a double axis tracker used for a concentrator module. These figures compare to fixed
array support structure costs of roughly $55/m2.11 Site preparation and installation currently
comprise 15-20% of area-related BOS costs and design and land costs are minimal in comparison,
less than $3/m2. Figure VII-8 shows how these costs break out among the various components.
The power conditioning equipment, which includes all the equipment which controls the DC
output of the solar cells and converts it to utility compatible AC current, constitutes the greatest BOS
cost after trackers and support structures. This involves complicated control systems that maintain
system security during lightning storms or circuit switching problems. The most expensive single
element of the power conditioning systems is the inverter that converts the DC power to AC power.
10 Southwest Technology Development Institute for EPRI, "Photovoltaic Field Test Performance Assessment:
1987,' March 1989; and Southwest Technology Institute for EPRI, 'Photovoltaic Field Test Performance
Assessment: 1988,' January 1990.
11 Ken Zweibel, Harnessing Solar Power The Photovoltaics Challenge, (New York: Plenum Press, 1990), p. 40.
VII - 12
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TABLE VII - 1
PERFORMANCE AND SUPPLY CHARACTERISTICS
OF OPERATIONAL PV POWER PLANTS
Plant Location,
Sjze
Phoenix, AZ
204 kW
Austin, TX
300 kW
Hesperia, CA
I.OOOkW
Sacramento
County, CA
2,350 kW
Steady Energy
Output (Daily)
June
120 kW
200 kW
400 kW
850 kW
Dec.
N/A
175kW
800 kW
450 kW
Operating Times
(a.m. to p.m.)
June
6 am to
8 pm
7 am to 9
pm
5 am to 7
pm
5 am to 8
pm
December
N/A
8 am to 6
pm
7 am to 5
pm
8 am to 6
pm
Capacity Factor
Monthly
30% - March - August;
13% - January; %5 -
September
30% - May -- October;
15% - November -
December; 0% -
January -- April
25% - 35%
40%- July; 10%-
December
Source: Photovoltaic System Performance Assessment for 1988, Electric Power Research Institute,
January 1990.
Low operation and maintenance costs of PV systems are one of their chief advantages. The
greatest contribution to O&M costs comes from repair and maintenance of trackers and support
structures. Not surprisingly, O&M costs for two-axis trackers are highest. Actual O&M costs for seven
PV systems which began delivering power between 1982 and 1986, including a two-axis concentrator
array ranged from 0.4 c/kWh to 7.0 c/kWh. EPRI estimated the potential O&M costs-the costs after
known problems are resolved~to range from 0.2 c/kWh to 1.2 c/kWh. Thus, reasonable O&M costs
VII -13
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FIGURE VII - 7
Gains in PV Cost and Module Efficiency
5000
CVJ "
o
o
4000
3000
2000
1000
0
Module cost ($/m2)
Module efficiency (%)
Electricity cost ($/kWh)
0
1973 1975 1977 1979 1981 1983 1985 1987 1989
Source: Ken Zweibel. Harnessing Solar Power: The Photovoltaics Challenge, 1990, p. 110.
VII - 14
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for the most expensive configuration, a two-axis tracker for a concentrator, can realistically be
estimated around 1 c/kWh.12
Photovoltaic systems are simple and modular, so the time needed for construction is relatively
short. Typical construction time from ground breaking to turn-key operation is about 6-8 months for
a large (1 to 2 MW) power installation. PV system installation costs range from about $6.00 per peak
Watt (Wp) for a 500 Wp system to $3.50/Wp for a 1 MWp system.
Sandia National Laboratories estimates that the total installed cost of an amorphous silicon
thin film system is currently between $4.50 to $5.00/Wp. The estimate is based on a 400 kW PVUSA
system (5% efficiency) installed for Pacific Gas and Electric. This installed cost estimate includes (1)
module cost of $2.00/Wp; (2) rack and mounting cost of $1.25/Wp; (3) an inverter cost of $0.50/Wp;
and (4) land and other costs of $0.25/Wp. All of these costs are likely to fall in the near future, as
discussed in later sections of this chapter.
Resources Recovered
In 1990, 12 MWp of grid connected PV capacity generated 25 GWh.13 However, the
majority of current solar energy production is not connected to the grid. For example, in 1989 alone,
the U.S. PV manufacturers shipped 14 MW of PV cells, 30% of the world market. Because of the high
capital cost of current PV systems, photovoltaic electricity is not cost-competitive where utility electric
power is readily available. The cost-effective market has been for small, remote, off-grid power
applications for meeting such power needs as communications, telemetry, signaling, cathodic
protection, lighting, pumping, refrigeration, and battery charging. Specific uses for PV in
communications include microwave repeaters, two-way radios and mobile radio systems, remote
control systems, radio communications, and telephones. PV walkway and yard lighting systems have
been commercial successes, with three million units sold worldwide since their introduction in 1987.
Demonstration projects using photovoltaics for central or decentralized utility power generation with
sizes of 1 kWp - 6 MWp have been reliably conducted under research and development and tax-credit
driven conditions. As PV power becomes cost-competitive, central and residential PV power systems
may help meet utility peaking and intermediate power generation needs.
12 Photovoltaic Operation and Maintenance Evaluation. Electric Power Research Institute, December 1989.
13 Nancy Rader, Power of the States. (Washington, DC: Public Citizen, June 1990.
VII - 16
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EMERGING CONVERSION TECHNOLOGIES
Performance/Efficiency
Some R&D efforts are focused on reducing the high energy and process input requirements of
single crystal PV cells by substituting polycrystalline and amorphous materials. As techniques for
reducing manufacturing costs are developed, trade-offs with reduced efficiencies and efficiency
degradation in such materials as amorphous silicon will require further attention. Experiments with
different base materials and the use of tandem cells with layered multiple PV junctions are leading to
major efficiency improvements from the current 10% -18% up to 20% - 32%.14
SERI has conducted research in advanced thin films development. Because they use less
material, solar modules comprised of thin films are anticipated to cost less than conventional modules.
Thin films can be produced by a variety of continuous manufacturing processes, and the potential for
high-throughput could also lower manufacturing costs. SERI's main objective for advanced thin films
research is to reach module efficiencies of 15%, while maintaining the advantages that have lowered
costs; achieving 20 to 30 year reliability is also critical. During the next five years, SERI will develop
four thin films: amorphous silicon, copper indium diselenide, cadmium telluride, and thin film silicon.
The efficiency of amorphous silicon devices gradually decreases with exposure to light, and
this cell instability has been a major focus of research. SERI predicts the degradation losses could be
held to 10% by making the amorphous silicon layers thinner. In contrast, copper indium diselenide
(CIS) appears to have few instability problems, and SERI hopes to develop CIS modules as stable as
crystalline silicon. SERI also plans to investigate other alloys such as gallium to replace indium and
sulfur to replace selenium. Cadmium telluride (CdTe) research efforts will focus on increasing the
efficiencies of cells toward their practical maximum of 20%. Thin film crystalline silicon research
focuses on making larger-area cells and on interconnecting the cells to the utility grid. SERI plans to
develop a prototype module capable of competing for remote and peak power applications that is
13% efficient, 4000 square centimeters, and susceptible to less than 5% degradation over a 10-year
period.
The SERI research goal for module development is to establish both collector module
technology and manufacturing technology for producing cost-effective PV modules. Research areas
include: new module design, efficiency improvements, increased yield, scaling to larger areas, more
14 H. M. Hubbard, "Photovoltaics Today and Tomorrow." Science, Volume 244, April 21, 1989.
VII - 17
-------
efficient use of materials or substitution of cheaper materials, and introduction of greater use of
automation. The PV Manufacturing Technology Initiative (PVMaT) is a major effort with the goal of
reducing production costs by a factor of 2 or 3 from current levels through advances in manufacturing
technology.
For utility scale applications, research has been conducted through the DOE in collaboration
with industry. The work has been conducted in industrial and university labs as well as DOEs support
laboratories. The program has two major strategies in place to deliver economical electric power to
utility grids: 1) development of concentrator and flat-plate PV systems based on high-efficiency
crystalline cell and module concepts; and 2) the development of flat-plate systems based on thin-film
cell and module technology with emphasis on low material and processing costs. As shown in Figure
VII-9. the historical trends in these cell efficiencies hold great promise for the future. The strategies will
be supplemented by direct research in solid-state materials, the development of advanced
characterization techniques, and continued characterization of the solar radiation source.15
Several utilities have shown an interest in selling or leasing small systems for remote
applications in their districts. Some utilities are also purchasing PV test projects to learn how PV
power interacts with their individual systems. PG&E's Photovoltaics for Utility Scale Applications
(PVUSA) project, funded jointly with DOE, Electric Power Research Institute (EPRI), the California
Energy Commission (CEC), and a number of utilities will result in approximately 1 MW of PV cell sales.
PVUSA consists of five parts, with two stressing new and emerging PV technologies and three
stressing large, utility scale projects. The emerging technology segments will include five 20 kW
systems, and the utility scale projects will include 200-400 kW systems to be installed in Davis,
California. This project will use 20 kW arrays to compare and evaluate current and emerging
technologies, including crystalline silicon, amorphous silicon, and new thin-film materials; assess O&M
costs in an electric utility context; compare the most promising technologies in different locations
within a utility service area; and provide U.S. utilities with hands-on experience in installing and
operating PV power generation systems.
Experience with test facilities suggests that to be competitive with future electric generation
options, PV modules must exhibit efficiencies above 15% at a cost somewhere between 6£ and 12C
per kWh, or installation costs between $1/Wp to $2/Wp.16 System efficiencies for PV currently
15 H. M Hubbard. 'Photovoltaics: Today and Tomorrow,' Science. Volume 244, April 21, 1989.
16 American Solar Energy Society. 'Assessment of Solar Energy Technology," May 1989.
VII - 18
-------
35
30
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FIGURE VII - 9
Progress in Laboratory Cell Efficiency
32%
J_
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J I
I I
78 79 80 81 82 83 84 85 86 87 88 89
Year
High Efficiency
Concentrator
Cells
23.2% Flat Plate
Single Crystal
Silicon Cells
15.7% Flat Plate
Thin Films
Source: Photovoltaic Energy Program Summary. U.S. Department of Energy, Volume I: Overview
Fiscal Year 1989, January 1990, p. 2.
VII - 19
-------
average 12% to 14% at costs of $8/Wp to $10/Wp, which includes BOS costs. EPRI predicts that BOS
costs will decrease through engineering and scale economies, but improvements must be made in
module efficiency and cost in order to reach these targets. The PVUSA project may demonstrate
efficiencies at levels in excess of 15% by 1992.
Costs
A recent analysis projected the cost reduction required for a representative PV technology to
produce utility-grade PV power competitive with a projected cost of 4-60/kWh from new conventional
plants.17 According to the analysis, current PV costs and competitive PV costs are as follows:
TABLE VII - 2
PHOTOVOLTAIC COST REDUCTIONS
COMPONENT
Module Cost
Area-Related BOS
Power-conditioning
Module Efficiency
Cost of DC electricity
AC cost w/storage
Current
$500/m2
$135/m2
$200/kW ($20/m2 )
10%-15%
37c/kWh
68C/kWh
Needed
$55/m2
$50/m2
$100/kW ($14/m2)
15%
40/kWh
7<5/kWh
% Change
(89%)
(63%)
(30%) - (50%)
0 - 50%
(90%)
(90%)
The biggest required gain, a ten-fold decrease in module cost, would bring module costs in
line with required BOS costs. Although a ten-fold decrease represents an ambitious cost goal, the
past 18 years of PV development have witnessed even greater PV cost reductions.
Potential Technology and Multiple Pathways
The costs of emerging technology suggest that simultaneous advances in several components
of PV systems will be needed to make large-scale, gnd-connected PV electricity competitive with
conventional power sources. Current research is pursuing many different pathways for each
component.
Manufacturing. Several silicon manufacturing processes are making promising gains in lowering cell
cost. These include casting, ribbon growth and melt spinning. In addition to keeping costs low, these
17 Ken Zweibel, Harnessing Solar Power The Photovoltaics Challenge, (New York: Plenum Press, 1990), p. 40
VII - 20
-------
processes are achieving cell efficiencies up to 17% and module efficiencies as high as 13%.18 Thin-
film silicon cells use less silicon, but at the expense of efficiency; so scientists are investigating
methods such as texturing the front surface and making the back surface reflective to increase the
likelihood that photons are absorbed by the cell. Theoretical efficiencies are as high as 19%. In April,
1991, Texas Instruments announced a new silicon thin-film manufacturing process that is expected to
lower PV electricity costs to 10c-15c/kWh around the turn of the century. The process involves
forming microscopic balls of silicon, spraying them on a preindented surface and using heat to bond
the spheres to the substrate. Although cell efficiencies are not expected to be extremely high,
projected costs are low because the manufacturing process is straightforward and does not require
high-grade silicon.19
Other techniques strive for higher efficiencies rather than minimum manufacturing costs.
These include passivation, texturing, point contact cells and microgrooved cells. Passivation is a
technique that involves applying a thin layer to the surface of a PV cell to correct for the fact that the
concentration of crystal defects is greater on the surface than in the interior of a crystal. A group at
the University of New South Wales achieved a cell efficiency of 23% in unfocused light in 1989, the
world record for a silicon cell. By chemically texturing the surface of a cell with a substance like
hydrazine or sodium hydroxide, fewer photons will be reflected from the cell. A point contact cell is a
unique design with the contacts on the back of the cell. Designed primarily for concentrators, it has
achieved an efficiency of 28% in focused light. Microgrooving (using a laser to cut grooves roughly
100 microns deep) does not raise efficiencies as much as the sophisticated passivation techniques,
but lends itself more readily to low-cost, automated manufacturing processes.
Materials. Materials research is currently focusing on thin-film processes for cadmium telluride
(CdTe), gallium arsenide (GaAs), and copper indium selenide (CulnSe), which lead to lower materials,
processing and handling costs. In April of 1991, SERI certified three world records. An encapsulated
4 ft2 CIS module achieved an efficiency of 9.7%, which is twice as high as any other thin-film module.
Two records for CdTe cells were set; the current mark stands at 13.4%.20
18 Ken Zweibel, Harnessing Solar Power The Photovottaics Challenge, pp. 114 - 118.
19 Personal communication with Ken Zweibel, Solar Energy Research Institute, May 30, 1991.
20 Personal communication with Ken Zweibel. May 30. 1991.
VII - 21
-------
Cell types. Many different muttijunction cells are achieving high efficiencies in concentrators. A three-
junction amorphous silicon and germanium cell reached 8.4%, a two-junction amorphous silicon and
CIS cell attained 10.5% and a two-junction aluminum, gallium and arsenic cell achieved 27.6%.21
Concentrators. Because concentrators focus sunlight onto a small area, they require much smaller
areas of cells. Furthermore, the conversion efficiencies increase when light is concentrated, so that
high-efficiency but expensive cells can prove competitive in concentrators. Several silicon and non-
silicon cells, both single and multijunction, have achieved efficiencies of 20% - 32%. These include a
module ready silicon cell of 27.2% efficiency and an experimental silicon cell at 28.2% efficiency.
Research is also being conducted on less expensive as well as non-imaging optics, which have
theoretical concentration yields four times as high as standard imaging optics.22
Storage. The development of electricity storage options would allow PV power to provide the
reliability needed for utility grid-connected applications. Storage is inherently less than 100% efficient
but the value of reliability can offset the costs and inefficiencies of storage. Possible storage media
include batteries, pumped hydro, compressed air, flywheels, superconductivity and hydrogen storage.
Batteries and pumped hydro represent the current commercial storage options, although batteries
have not yet been scaled to central station utility size. Pumped storage reservoirs are typically filled at
night and hence do not fit PV output patterns. The other technologies are generally uneconomic and
in nascent stages of development, but hold great potential for making significant impacts on the
implementation of PV.
Power conditioning, tracking and support structures. Power conditioning systems currently achieve
high efficiencies (95%) and acceptable reliability.23 Manufacturing and operating costs of balance of
system components can be lowered, while maintaining or improving performance, through continued
applied engineering and research. Progress in improving tracking systems and lowering costs can
enhance energy capture and can dramatically improve the economics of photovoltaic systems.
MARKET ASSESSMENT
Projections of future PV sales are extremely sensitive to the presumed timing of cost
reductions, especially when future cost and performance attain certain thresholds that make them
21 Photovoltaic Program Summary, 1990
22 Roland Winston. "Nonimaging Optics,' Scientific American. Volume 264, Number 3, March 1991, pp. 76-81.
23 EPRI Photovoltaic Field Test Performance Assessment: 1988.
VII-22
-------
competitive in utility power generation. A recent report by the Department of Energy and the Solar
Energy Research Institute analyzed the impacts of PV technology development on future
deployment24. The DOE/SERI BAU projection provides the EPA Base Case for PV electric
generation. Table VII-3 shows the DOE/SERI and EPA windpower scenarios.
TABLE VII - 3
PHOTOVOLTAIC SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
800
3,600
1,600
1,000
4,400
Generation
2000
(GWh)
2,000
8,800
3,900
2,000
8,800
Capacity
2010
(MW)
6,100
27,100
15,800
7,400
98,000
Generation
2010
(GWh)
14,600
65,300
38,000
14,600
195,100
1990: 12Mw 25 GWh
The EPA Enhanced Market PV scenario assumes that an intensified RD&D budget will bring
down the costs of materials and production, and that environmental impacts will be incorporated into
utility planning. PV is very responsive to intensified R&D, and prices should drop significantly by the
year 2000 given sufficient research support. The Enhanced Market scenario for 2000 is based on the
alternative PV growth scenario described in the DOE/SERI report (page G-10). Tables VII-4 and VII-5
give the model results for the PV scenarios. The EPA Enhanced Market scenario assumes that
average PV generation costs could be reduced to 11.5 c/kWh by 2000 and to 6.4 c/kWh by 2010 (and
lower in regions of good insolation where capacity factors approach 30%). This would require capital
costs to fall to roughly $2,100 per kW by 2000 and $1,150 by 2010, compared with the DOE/SERI BAU
assumptions of $3,500 in 2000 and $2,100 in 2010. Thus, PV cost reductions are accelerated by at
least a decade over the SERI BAU assumptions.
24
The Potential of Renewable Energy An Interlaboratory White Paper. Prepared for the Office of Policy,
Planning and Analysis, U.S. Department of Energy, March 1990, p. G-10.
VII - 23
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Basing growth projections on cost reductions, a capacity of 4,400 MW could be installed by
2000. In the Enhanced Market scenario, the market would expand at an average annual growth rate
of 26% per year between 2000 and 2010, by which capacity reaches approximately 98,000 MW. This
growth would be distributed across the U.S., with over 40% of growth occurring in the South, and
approximately 20% in each of the remaining three regions.
Costs
Even with the cost reductions assumed here, PV generation costs remain higher than avoided
conventional systems in all but two regions (California and Southwest) in 2010. The conventional
generation displaced by PV systems is primarily high cost summer peak electricity, but PV systems do
not displace an equivalent amount of conventional capacity because of limited capacity factors and
the intermittent resource. Since the costs of PV systems are higher than the avoided cost in most
regions, environmental performance is the main driving force in the Enhanced Market scenario. By
2000, PV remains 5 c/kWh to 12 c/kWh higher than avoided costs. The differential narrows by 2010 in
most regions, with the PV in the Northeast remaining 3 c/kWh above conventional costs; PV drops
below conventional costs in the Southwest and California; while other regions' PV costs fall in between
these two extremes.
Air Pollution Prevented
The environmental benefits from PV generation in the Enhanced Market scenario include
annual SO2 reductions of almost 900,000 tons by 2010 (primarily in the Southeast and North Central
regions), and annual NOX reductions of almost 700,000 tons (primarily in the Southeast and
Northwest/Mountain regions). Over 190 million metric tons of CO2 would be displaced annually by PV
by 2010, mostly in the Southeast, Southwest, and Northwest/Mountain regions.
VII - 26
-------
CHAPTER VIII
SOLAR THERMAL ELECTRICITY GENERATION
Solar thermal systems concentrate the sun's radiation to attain high temperatures, and then
convert this thermal energy into mechanical energy, electricity, or process heat used in the production
of fuels and chemicals. The use of solar thermal power is not a new phenomenon: French scientists
demonstrated solar thermal engines for pumping and distilling water, and for printing newspaper, at
the Paris Exposition in 1878. In the early 20th century, a 4.5 horsepower solar engine pumped water
for a farm in California, another solar engine pump operated in the desert in Needles, California, and
an American engineer designed and built a solar engine that produced 70 horsepower using a system
of trough concentrators.1
Currently, 354 MW of solar thermal capacity provides enough electricity in southern California
to serve the residential needs of 500,000 people. Continued research and commercial deployment is
likely to bring down the cost of solar thermal electricity and expand the region of cost-effective grid-
connected solar thermal electricity.
RESOURCE BASE
Total U.S. Resources
A recent study conducted by Meridian Corporation for DOE estimates the 30 year solar
thermal energy resource at one million quads.2 This value, which is the same as the biomass and
photovoltaic energy resource base, is the product of the average incident radiation on the surface of
the U.S. - about 4.32 kWh/m2 - and the proportion of the radiation which Meridian considers intense
enough to be a potentially exploitable resource, which they estimate at 70%. Approximately 45% of
the U.S. surface area is committed to uses such as national parks and cropland that do not lend
themselves to solar thermal energy, which lowers the accessible solar thermal resource base to
approximately 600,000 quads. The portion of the resource considered economically exploitable by
solar thermal energy (e.g., energy reserve) is less than 0.1 quads.
1 Solar Technical Information Program, "Solar Thermal Power," February, 1987.
o
Characterization of U.S. Energy Resources and Reserves. Prepared for the U.S. Department of Energy by
Meridian Corporation, June 1989.
VIII - 1
-------
These estimates of resource base and accessible resources should be regarded as extreme
upper bounds for solar thermal conversion. Solar thermal technology relies on direct sunlight and
cannot utilize indirect (diffuse) radiation, which makes up a sizeable part of the insolation estimate.
On a clear day, direct radiation comprises about 80% to 90% of the total received solar radiation, but
on cloudy days the direct portion accounts for only 30% to 50% of the total.
Geographic Distribution
Because solar thermal electric generation relies on direct solar radiation, the geographic
distribution of solar thermal resources is more constrained by prevailing cloud conditions than are
photovoltaic resources. The best solar thermal resources in the U.S. are found in the arid Southwest.
Figure VIII-1 shows the geographic distribution of annual average daily direct solar radiation, which
ranges from approximately 8 kWh/m2 in the Southwest to less than 3 kWh/m2 in the Northwest and
Northeast. Florida an area traditionally thought of as sunny, does receive high global solar radiation -
- 70% of the national maximum. However, Florida is not a likely she for solar thermal plants because
its annual cloud cover and precipitation patterns result in low levels of direct solar radiation.
The geographic range of economical solar thermal electric generation is confined to the desert
southwest under current costs and regulation. Lower costs and regulatory reform could expand the
viable range of this technology to a region that would span the entire Western U.S. beginning in
central California, ranging north to the Canadian border and extending as far east as Iowa, Missouri,
and Arkansas.3
CONVERSION TO ELECTRICITY
A solar thermal plant converts solar energy to useable energy with four basic subsystems:
concentrator, receiver, transport/storage, and conversion/delivery. Solar concentrators focus large
amounts of solar energy onto the receiver, which heats a fluid used to generate electric power or to
provide heat for industrial applications. To provide power, the fluid must be transported through a
piping system, or stored for later use. At point of use. the heat is converted to electric power and
delivered to the grid, or used to produce steam, hot water, or hot gases for industrial applications.
3 James Bazor, Testimony before the U S. Department of Energy National Energy Strategy Hearing, Tulsa,
Oklahoma, August 8, 1989.
VIII - 2
-------
FIGURE VIII -1
Annual Average Daily Direct Solar Radiation
'0 I?
Annual Average Dally
Direct Normal Solar Radiation
MJ/nV kWh/m" Btu/tt"
UUIU1 8-12
1 1 J 12-16
E^§ 16-20
20-24
24-28
28'
22-3.3 700-1050
33-44 1050-1400
44-5.5 1400-1750
55-66 1750-2100
66-77 2100-2450
7 7* 2450-
NOTE Numbered contours represent MJ/m2
Direct (beamt radiation can be converted into high temperature steam or
directly into electricity by concentrating collectors which track the sun.
'Approximate Values
Source: Solar Energy Research Institute (September 1983). Solar Energy: A Brief Assessment
VIII - 3
-------
Existing Technologies
Four basic solar thermal energy technologies are used to concentrate or absorb sunlight:
parabolic troughs, parabolic dishes, central receivers, and solar ponds. With the exception of solar
ponds, these are all considered concentrating collector systems. Figure Vlll-2 displays the collector
system technologies.
Parabolic Troughs. Parabolic troughs are reflective troughs, curved in one dimension, that track the
sun on a single axis and focus the sun's light onto the receiver, a tube located at the trough's focal
point. The receiver is a specially coated pipe inside a glass vacuum tube. The heat transfer fluid in
the pipes is typically a synthetic oil heated to over 700 °F and piped to a heat exchanger to create
superheated steam for the turbine generator.
Trough technology is currently the technology most in use, and a key advantage of the
parabolic trough system is modularity. A basic module is a row of reflectors activated by a drive
motor to track the sun. A control system operates as many modules as necessary to heat the fluid in
the pipes to the temperature required for process heat The process heat created can be increased
in temperature using fossil energy for applications such as driving a generator for electric power
production. Hybrid natural gas-solar thermal electric systems expand power generation beyond
sunlight periods and provide reliable power during cloudy times. Several natural gas-solar hybrid
plants have been commercially deployed in California Figure VIII-3 shows the parabolic trough
system of Luz International Ltd., a major solar thermal electricity producer.
Parabolic Dish Systems. Dish systems use parabolic reflectors in the shape of a dish to accurately
focus the sun's rays onto a receiver mounted above the dish at its focal point. The solar energy heats
fluid circulating through the receiver and this hot fluid can either be piped to a central heat exchanger
and turbine generator to be used for a variety of uses, or electric power can be generated by a small
engine mounted at the focal point of the dish. A single parabolic dish, 15 meters in diameter, can
achieve temperatures in excess of 2700 *F and produce up to 50 kW of electricity.4 Solar dishes
require very accurate tracking devices but they achieve the highest performance of all concentrator
types in terms of annual collected energy and peak solar concentration.
A dish-Stirling system is named for its two major components: the dish-shaped solar
concentrator and a Stirling heat engine. Stirling engines can operate efficiently at the high
temperatures attained by dish reflectors. The engine is a sealed system filled with gas, and as the gas
4 Solar Technical Information Program, 'Solar Thermal Power,' February, 1987.
VIII - 4
-------
FIGURE VIII - 2
Solar Thermal Collector System Technologies
Concentrator
Parabolic Trough Systems
Receiver
Concentrator
Parabolic Dish Systems
Receiver
Central Receiver Systems
VIII - 5
-------
FIGURE VIII - 3
The Luz System
SOLAR
COLLECTORS
o
ELECTRIC GENERATOR
AND TRANSFORMER
VIII - 6
-------
heats and cools, its pressure rises and falls. The change in pressure is controlled to drive the pistons
inside the engine, producing mechanical power. The Stirling engines are either kinematic or free-
piston. In the kinematic model, the pistons are physically linked to coordinate their movement. In the
free-piston model, there is no mechanical link between the pistons, and motion is dependent upon
gas springs.
The Department of Energy has supported several parabolic dish projects. These include the
Vanguard solar dish in Rancho Mirage, California, and the Solar Total Energy Project (STEP) in
Shenandoah, Georgia. The Vanguard, which was jointly funded by Advance Corporation, is a 36 foot
diameter parabolic dish concentrator combined with a Stirling engine generating 25 kW of electric
power. In 1988 the system converted 29.4% of available solar energy to electricity, a record for any
solar experiment. The STEP system, a joint venture between DOE and Georgia Power, incorporated
114 parabolic dish collectors and a steam powered generator to produce up to 400 kW of electric
power, 1400 pounds of steam at 350 °F, and 257 tons of air-conditioning per day for use in an
adjacent textile mill. Funding for STEP was terminated and the project was mothballed in November,
1988. Demonstrating a much larger application of parabolic dish technology, the 4.4 MW LaJet
Solarplant 1 near San Diego makes steam for two turbine generators, using an array of 700 dish
concentrators.
Central Receivers. Central receiver solar thermal systems feature a central receiver point on a tower
that collects focused sunlight from a large surrounding array of heliostats that track the sun. In 1965,
the first true central receiver system, by today's standards a small one, was built near Genoa, Italy.
Subsequent plants were built that produced steam in the range of 900 °F to 1100 °F. Around the
same time, solar furnaces were being built in France using large, computer guided flat mirrors
(heliostats) to redirect the solar beam (direct sunlight) into a fixed parabola. Tilting the heliostats and
aiming them toward the receiver on top of the fixed parabolic structure resulted in a configuration
much like the central receiver plants that are being built today. A heat transfer fluid, which could be
steam, molten salt, or sodium at temperatures of 1000 °F to 2700 °F, can be used to drive a turbine to
produce electric power. Given a good solar resource and enough heliostats, temperatures on the
receiver can exceed 1800 °F for gas-cooled receivers, while steam Rankine cycle turbines can
generate electricity with working temperatures under 1100 °F.5 The principal advantage of central
receiver systems is their ability to efficiently deliver energy at very high temperatures. Figure VIII-4
shows a central receiver system.
5 A rankine cycle engine is a type of heat engine, a thermodynamic device which converts thermal energy to
work. The working fluid used in the conversion process is usually steam, but other fluids can be used.
VIII - 7
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The only commercial demonstration built in the U.S. was the Solar One plant in Barstow,
California. Solar One was a 10 MW generating plant using a water/steam receiver that contributed to
the Southern California Edison (SCE) grid between 1982 and 1987, while operating on a five year
research and development contract with USDOE. The project consisted of 1,818 individual tracking
heliostats with 766,000 square feet of reflective area that focused enough sunlight on the receiver to
achieve a temperature of 1150 T. Through August 1986, the maximum annual output was 8,816
MWh, demonstrating about a 10% capacity factor. In addition to direct steam use in the turbine
generator, the plant used a thermal storage unit with capacity of about 34,000 cubic feet of thermal oil,
which was used to produce steam for the turbine during cloudy periods and after sundown.6 The
project provided data on the operation, reliability, and maintenance of central receiver power plants.
As a result of experience with Solar One, improved heliostats, receivers, and computerized controls
are being designed, which will yield more cost-effective operation. The Solar One plant has been
dormant since 1987. the last year of the R&D contract with DOE, but is being maintained by SCE for
future use. The National Renewable Energy Laboratory (formerly SERI) is currently attempting to raise
the necessary funds to use the facility to test molten salt as a receiver medium.
Solar Ponds. Solar ponds control the fluid composition, density, and convective flows of different
temperature fluids in a pond exposed to the sun to maximize the temperature difference between the
bottom and top layers of a pond warmed by the sun. This temperature difference can be harnessed
to drive a turbine generator or produce process heat. In 1984, Ormat Systems constructed a 62 acre
solar pond near the Dead Sea in Israel, which supplies 5 MW at peak operation and about 1,500 MWh
per year at about 10c/kWh. In the U.S., the Bureau of Reclamation has funded a 36,000 ft2 solar pond
project that uses a 100 kW power system. After the oil shortages of the 1970s, the U.S. DOE funded
several pond research projects aimed at producing space heating and cooling and industrial process
heat. DOE funding for solar ponds was terminated in 1983.
Stand-Alone Systems. Some of the earlier system experiments used trough technology and heat
engines to produce power for irrigation systems. The largest, the 150 kW Coolidge Solar Irrigation
Project, was funded through a cooperative agreement between DOE and the state of Arizona. The
operation of the plant demonstrated a 'hands-off automated control system and established an
outstanding reliability record, operating during 97% of the adequate insolation.
6 Solar Technical Information Program. "Solar Thermal Power.' February 1987.
VIII-8
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FIGURE VIII - 4
Solar Thermal Central Receiver System
(a) Tracking
Optics
Solar Thermal System. Solar thermal systems convert the sun s radiation to useful products (such as electncity. fuels, or direct heat) via a
thermal process. The basic elements of anv solar thermal design are (a) the tracking optics used to concentrate the sun s energy, (b) the
receiver, which trans!ers the sun s energy to a fluid, (c) piping to transfer the hot fluid to (d) storage for later use or directly to (e) the
conversion device, which converts the heat in the fluid to a usable form such as (f) electncity or process heat
VIII - 9
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Resources Recovered
In 1990, 279 MW of installed solar thermal capacity produced 765 GWh of electricity, yielding
a natural gas-assisted capacity factor of 31 %. LaJet's parabolic dish system accounted for 5 MW of
the installed capacity; Luz's parabolic trough systems comprised the rest. Luz currently has 354 MW
of capacity on-line in southern California
Current Economics
Costs for central receiver systems have declined from the $15,000/kW for the Barstow Solar
One project to about $3,000 to $4,000/kW in 1986. Cost trends for parabolic dishes have also
witnessed a rapid decline over the last decade. Area-related costs of collectors have dropped from
$lOOO/m2 in 1978 to less than $180/m2 for the LaJet dish and $160/m2 for the Acurex dish in 1987.
System costs have dropped from $13,500/kW to about $2,500/kW in that time.7
The capital cost of parabolic troughs with gas enhancement is currently $3000 - $3500/kW.
Levelized real (1988 dollars) costs of energy have dropped from 250/kWh in 1984 to about 80/kWh
today. The solar portion of the costs has decreased by a factor of five since the first commercial
installation built in 1984. The Solar Electric Generating System (SEGS I) produced 13.8 MW using
parabolic trough collectors and oil thermal energy storage. SEGS I and subsequent SEGS plants led
to the negotiation of contracts with Southern California Edison (SCE) for nearly 600 MW to be built in
30 MW increments in the Mojave Desert. By late 1988, Luz had built six additional 30 MW facilities
and was delivering a total of 194 MW to the SCE grid. The next operational plants, SEGS VI and VII at
30 MW, produced power at about Hc/kWh. Responding to the 1987 legislation that increased limits
on power from Qualifying Facilities (QFs) from 30 MW to 80 MW, Luz completed SEGS VIII in
December of 1989 and SEGS IX in late 1990, bringing their total installed capacity to 354 MW; the
latest plants produce power at 8c/kWh. The California Public Utilities Commission directed San Diego
Gas and Electric (SDG&E) to enter into an 80 MW power purchase agreement with Luz.8 Table VIII-1
details characteristics of current and future SEGS. Recent events, however, have clouded the future
viability of solar thermal electricity generation. Citing the recent recession and depressed oil and
natural gas prices, as well as the failure of California to extend property tax relief and the expiration of
William B. Stme, Progress in Parabolic Dish Technology. Solar Energy Research Institute: June 1989.
8 Conversation with Michael Lotker. April 3, 1991.
VIII - 10
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TABLE VIII - 1
LUZ SOLAR ELECTRIC GENERATING SYSTEMS
Plant
SEGSI
SEGS tl
SEGS III
SEGS IV
SEGSV
SEGS VI
SEGS VII
SEGS VIII
SEGS IX
SEGSX
through
SEGS XII
SEGS XIII
Capacity
(MW)
13.8
30
30
30
30
30
30
80
80
220
80
Capital
Costs
($/kW)
4,500
3,200
3,620
3,760
4,020
N/A
3,870
3,788
3000-
3500
3000-
3500
2000
Collector
Area
-------
Typical construction time from ground breaking to turn-key operation for a major solar thermal
energy system is 8 to 18 months; Luz's latest plant was financed, constructed and brought on-line in
71/2 months.10 In order to provide continuous power generation during cloudy and night-time
periods, the Luz power plants use up to 25% natural gas during non-solar periods. Gas use is
restricted to 25% under current PURPA regulation, a restriction that would not apply to utility-built solar
thermal hybrid plants. By extending the period of operation through increased natural gas use, the
cost per kilowatt can decrease, because the fuel cost is offset by greater capital utilization. In
addition, solar thermal electric plants are likely to have scale economies that were unrealized under
the 80 MW PURPA restriction in effect until 1990.
Storage presents another option to extend the period of operation. Storage systems, such as
batteries and thermal storage, sacrifice instantaneous power supply during the peak periods because
they divert some of the energy to maintain several hours of stored electricity. For example, a 1 MW
plant with storage may be capable of providing 2 MW of power, but instead uses the extra for storage.
The economic tradeoff is one between greater (but intermittent) peak power and lower (but firmer)
capacity. Storage capacity may enable a solar thermal plant to obtain some capacity credit.
However, pumped storage hydro is probably not a viable storage option since pumped storage plants
typically fill reservoirs at night, and water may not be available in arid regions for dedicated pumped
storage plants.
Even without storage, solar thermal plants can operate when very brief cloud cover occurs,
since the working fluid has some thermal storage capacity. However, extended cloud cover will
reduce power output to zero. This is different than the type of intermittent output expected from a
photovoltaic (PV) plant. If a single cloud shades a PV plant, output would immediately drop by 30% to
50% but would quickly recover full power as the cloud passes. Because PV technology utilizes
indirect as well as direct light, however, PV systems can continue to operate at 30-50% of peak
sunlight capacity under extended cloudy conditions.
EMERGING TECHNOLOGIES
During the past decade, solar thermal systems have improved with the development of more
efficient concentrators, longer-lasting and cheaper reflective materials, and a variety of receivers and
systems. These advances have positioned solar thermal systems for utility-scale applications. In
addition to generating electricity, solar thermal systems can be used for destroying hazardous wastes,
liquefying coal, and processing metals and chemicals due to the high temperatures they achieve and
10 Solar Industry Journal, Fourth Quarter 1990, Volume 1, Issue 4, p. 6.
VIII - 12
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the energetic properties of the solar spectrum. Spin-offs from these areas may have applications in
solar thermal electricity generation. The progress made by Solar One and early commercial thermal
plants along with the prospect for producing vital fuels and chemicals through solar thermal
technology are encouraging, but further development of system components is necessary.
Potential Technology and Multiple Pathways
Each of the four solar thermal electric technologies - parabolic troughs, parabolic dishes,
central receivers, solar ponds - employs the same basic subsystems: concentrator, receiver,
transport/storage, and conversion/delivery. Advances in a given technology will result from research
gains not just in that technology but also from advances in any of its subsystems, which are
themselves occurring along a variety of pathways. For example, research on concentrators in 1989
involved heliostats, parabolic dishes, optical materials and structural analysis.11
Reflectors. When the Solar One plant was built, the cost of its heliostats was approximately 60% of
the total cost of the power plant. Advanced heliostats are now 3 to 4 times larger (150 square meters
instead of 40 square meters) than the originals, reducing the (per area) cost of the heliostat. In
addition, the heavy silvered glass of the original heliostats is being replaced with lightweight silvered
plastic, allowing for lighter and simpler supporting structures. An example is the stretched membrane,
where the reflective material is stretched over a metal rim. Small stretched membranes were used in
the LaJet Solarplant 1 parabolic dishes. Further development of the membrane reflectors should lead
to larger, more efficient designs at a lower cost.12
Receivers. The future potential for central receiver technology remains uncertain. Industry/utility
teams have identified the need for a commercial 10-30 MW commercial project to validate current
technology at a scale larger than component tests. Next generation plants will likely use stretched
membrane heliostats and advanced direct-absorption receivers.13 Further improvements for central
receivers will decrease the size and weight of solar receivers by using materials and fluids that absorb
more energy. For example, advanced receivers using molten salt or sodium as heat transfer fluids
11 Solar Thermal Program Summary, Volume I: Overview, U.S. Department of Energy, January, 1990.
12 Solar Technical Information Program, "Solar Thermal Power," February, 1987.
13 The U.S. Department of Energy, "Bringing Solar Technology to the Marketplace - A Report to the U.S.
Congress,' August 1988.
VIII - 13
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could be 80% smaller than the Solar One steam receivers. The new fluids can also be stored at high
temperature and low pressure for plant operation during long hours of reduced sunlight.14
Solar Ponds. Many questions remain unanswered about the technological and commercial feasibility
of solar ponds. Research needs are different for natural and constructed ponds, but common to both
is the need to develop pond and power system maintenance procedures and to investigate alternate
salts, salt management, and load matching and optimization. For natural ponds, further research
needs include soil impermeability treatment studies, plastic liner development, and control of ground
heat losses.15
Costs
Costs of central receivers, parabolic dishes and parabolic troughs have been falling steadily.
Although commercial experience with central receivers is limited, costs are projected to decrease to
$1,500/kW by 1995-2000. For parabolic dishes. SERI forecasts system costs of $1000/kW, energy
costs of 5c/kWh and concentrator costs of $i40/m2 by 1995.16 Luz estimates that the levelized cost
of electricity from their third generation parabolic trough plants, of which 160 MW have already been
brought on line, will remain at 8c/kWh. Their next generation of plants is projected to cost $2000/kW
installed, and produce electricity at a levelized real cost of 6c/kWh. These cost reductions will be due
to technological and engineering advances, Luz's growing experience with the commercial application
of solar thermal systems, improved manufacturing techniques, and economies of scale, which were
not available before Congress rescinded the 80 MW PURPA limit in 1990.
In the recent DOE/SERI analysis of the development of solar thermal electric generation with
storage, costs and energy supply are projected forward from 1988.17 Capital costs for systems with
storage drop from $3000/kW in 1988 to $2400/kW (BAU scenario) or $1750/kW (Intensified RD&D) in
2000. Costs were projected to decline further by 2010, ranging from $1530/kW (BAU) to $1450/kW
(RD&D) in 2010. O&M costs are projected to remain constant at 2.0 c/kWh under both scenarios.
Given these assumptions, levelized energy costs fall from 15.8 c/kWh in 1988 to 7.5 c/kWh (BAU) to
6.0 C/kWh (RD&D) in 2000. and decline to 5.5 c/kWh (BAU) to 5.0 C/kWh (RD&D) in 2010.
14
Solar Technical Information Program, "Solar Thermal Power," February 1987.
15 The U.S. Department of Energy. 'Bringing Solar Technology to the Marketplace - A Report to the U S.
Congress.' August 1988.
16 William B. Stme, Progress in Parabolic Dish Technology, Solar Energy Research Institute. June 1989.
17 The Potential of Renewable Energy: An Intertaboratory White Paper. Prepared for the Office of Policy,
Planning and Analysis, U.S. Department of Energy. March 1990.
VIII - 14
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MARKET ASSESSMENT
The EPA Base Case and Enhanced Market scenarios are derived primarily from the DOE/SERI
scenarios and are shown in Table VIII-2. The DOE/SERI BAU scenario yields an increase of solar
thermal electric from 0.004 quads of primary energy to 0.29 quads in 2010, an average annual growth
rate of almost 21 %.18 The National Premiums policy scenario would triple solar thermal electric
generation compared to the BAU projection, while the RD&D policy would lead to 1.01 quads by 2010.
In all scenarios, solar thermal systems are located only in the West and South.
The DOE/SERI analysis considers hybrid systems, along with stand-alone systems with and without
storage (peaking systems), but does not indicate which technologies would be chosen. The
economics of storage and fuel backup are probably more favorable from the utility perspective than
intermittent peak power, unless the solar resource is extremely dependable or located in an area
where weather forecasting is reliable. However, the DOE/SERI report suggests that storage systems
will be improved to the point where they are more economical than natural gas backup systems.
The EPA Base case is identical to the DOE/SERI BAU scenario (as noted on Table VIII-2, the
generation figures in the EPA scenarios include the portion of natural gas hybrid systems attributed to
gas-fired operation). Capacity installed between 1990 and 2000 is assumed to be natural gas hybrid
operating at 25% gas backup in all regions. Between 2000 and 2010, capacity is assumed to be a
mixture of peaking (stand-alone) stations and systems with storage.
The Enhanced market scenario assumes that additional R&D brings about cost reductions
indicated in the DOE/SERI Intensified RD&D scenario, but that additional growth in market deployment
in both hybrid and stand-alone systems is spurred by environmental concerns. Chapter X gives
detailed information about the input assumptions for the solar thermal market analysis for hybrid and
non-hybrid systems.
Tables VIII-3 and VIII-4 show the model results for costs and air pollution prevented. Because
solar thermal systems rely on direct solar radiation, they are not economic in areas that experience
clouds and haze during much of the year. Therefore, solar thermal electric generation is assumed to
grow only in the Southwest, Northwest/Mountain, and California regions. While natural gas backup
beyond the 25% assumed in this analysis could extend the range somewhat, solar thermal systems
would still be most economic in these three regions. In the Base Case, annual solar thermal electric
generation grows by 30,400 GWh between 1990 and 2010. Over 75% of the growth occurs in the
18 DOE/SERI projections only account for the solar energy input to hybrid systems. Thus, actual generation
from solar hybrid systems may be higher than these figures indicate.
VIII - 15
-------
TABLE VIII - 2
SOLAR THERMAL SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&O
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
3,200
6,000
5,300
3,800
7,200
Generation
2000
(GWh)
8,800
16,600
14,600
11,700
22,100
Capacity
2010
(MW)
10,300
35,900
32,000
9,600
35,200
Generation
2010
(GWh)
28,300
98,500
87,800
31,200
115,100
1990: 300 800
Note: DOE/SERI generation figures are solar contribution only. EPA figures include some fossil fuel
(natural gas) input for hybrid systems.
Southwest region, which includes Texas, Arizona and New Mexico. In the Enhanced Market scenario,
solar thermal electric generation grows by over 114,300 GWh between 1990 and 2010, again mostly in
the Southwest.
Costs
Because solar thermal electric systems with natural gas backup can provide reliable peak
power, avoided utility costs are fairly high. By 2010 in the Base Case, average solar thermal
generation costs are 0.1 c/kWh lower than conventional costs in the Southwest regions, and 1.3
C/kWh lower than conventional costs in California In the Enhanced Market scenario, costs by 2010
are significantly lower than conventional costs; solar thermal generation costs 0.5 C/kWh less than
conventional generation in the Southwest and costs 1.8 e/kWh less in California.
VIII -16
-------
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Air Pollution Prevented
Because solar thermal electric generation occurs only in the West, where natural gas and oil-
fired generation are the marginal fuels and where coal-fired sources are fairly well controlled, S02, PM,
and CO2 emission reductions per kWh generated are generally lower than other renewable
technologies. However, solar thermal generation reduces a significant amount of air pollution. In the
Enhanced Market scenario for 2010, annual SO2 emissions are reduced by 142,000 metric tons; NOX
emissions by 361,000 metric tons; and CO2 emissions by 81 million metric tons.
VIII -19
-------
CHAPTER IX
WINDPOWER
Wind energy has powered sailing vessels for thousands of years, and has been used for
centuries to power windmills for pumping water and grinding grain. In 1941, energy from wind was
first used to generate grid connected electricity. Wind energy generation has increased dramatically
during the past decade, particularly when oil prices were high and major federal and state tax
incentives and R&D expenditures were in place. Throughout the period, wind energy costs steadily
declined.
Wind energy development initially focused on the individual wind turbine, but by the late 1970s
the focus shifted to minimizing the cost by maximizing the total generation from groups of wind
turbines. Since 1981, thousands of turbines large enough to supply power to utility systems have
been installed and the numbers continue to grow. With a maturing of technology and a shakeout and
consolidation among manufacturers and developers in recent years, the wind industry is poised to
make significant commercial power contributions in the 1990s.1
RESOURCE BASE
The total wind energy resource in the U.S. is defined as the amount of energy contained in all
air of wind power classes 2 through 7 (see below), which means the energy in all air moving faster
than 6.1 meters/second at a height of 50 meters. This resource totals approximately one million
quads. The accessible wind resource equals the energy contained in all air of wind power classes 3-7
which would strike the rotors of an adequately spaced array of commercially available wind turbines
covering the available land in the U.S.2 The available land does not include forested areas, parkland
and wilderness areas, national security areas and the surfaces of lakes, streams and rivers. The
accessible wind resource is about five thousand quads. Meridian equates the subset of the
accessible resource which can be economically converted to electricity with the installed wind capacity
of wind turbines.
1 Taylor Moore, John Scnaefer, and Edgar DeMeo, 'Excellent Forecast for Wind," EPRIJoumal, June 1990.
2 This is defined as MOD 5-B wind turbines, spaced 10 rotor diameters apart in each row with a 5 diameter
spacing between rows. See Characterization of U.S. Energy Resources and Reserves, prepared for the U.S.
Department of Energy by Meridian Corporation, June 1989, from which this information is taken.
IX-1
-------
Another recent resource assessment performed by Pacific Northwest Laboratories (PNL)
evaluated the windpower potential for the U.S. under various assumptions regarding conversion
technologies and land-use restrictions.3 Although land-use factors eliminated roughly 70% of the
energy potential from the resource base in the most restricted scenario, the estimated remaining
potential was larger than the wind energy reserves identified in the Meridian report and would exceed
total U.S. electricity consumption in 1990.
Geographic Distribution
The Wind Atlas prepared by Pacific Northwest Laboratory for the U.S. Department of Energy
(DOE), categorizes wind resources according to wind power classes.4 Measured at 50 meters above
the ground, wind resources are categorized into the following classes: Class 2 is between 12.5 and
14.3 mph; Class 3 is between 14.3 and 15.7 mph; Class 4 is between 15.7 and 16.8 mph; Class 5 is
between 16.8 and 17.9 mph; and Class 6 is between 17.9 and 19.7 mph. The Atlas further defines
wind resources potentially suitable for wind energy applications as those rated in Class 3 or above.
The Atlas also depicts windpower data on a series of maps, which can be used for initial resource
assessments. However, the data necessary to successfully site wind turbines requires a far more
detailed evaluation of site-specific patterns.
Many areas within the United States have suitable wind energy resources. These areas
include much of the Great Plains from northwest Texas and eastern New Mexico north to Montana;
North Dakota and West Minnesota; the Atlantic Coast from North Carolina to Maine; the Pacific Coast
from California to Washington; and the Texas Gulf Coast. Further, many ridge crests and mountain
summits throughout the Appalachians and the Western U.S., as well as specific wind corridors
throughout the mountainous western states have good wind resources. Figure IX-1 displays regional
wind resources.
According to the maps found in The Atlas, the most powerful wind resources, rated in the 5 to
6 power class, are concentrated in the Pacific, Mountain and Northeastern regions. These regions
correspond to the Washington/Oregon, West Mountain, New England, and Mid-Atlantic regions
defined in this analysis. Good wind resources, those in Class 3 or 4 rating, can be found in northern
3 D. L Elliot, LL Wendell, and G.L Gower, 'U.S. Areal Wind Resource Estimates Considering Environmental
and Land-Use Exclusions" presented at the Amehcan Wind Energy Association (AWEA) Windpower '90 Conference,
September 28, 1990.
4 D.L Elliot, C.G. Holladay, W.R. Barchet. H.P. Foote, and W.F. Sandusky, Wind Energy Resource Atlas of the
United States. (Golden, Colorado: Solar Energy Research Institute, DOE/CH 10093-34, 1986).
IX-2
-------
FIGURE IX - 1
Regional Wind Resources
Wind Resource Map of the United States
Source: Wind Energy Resource Atlas of the U.S., U.S. Department of Energy, March 1987
IX-3
-------
and southern Great Plains regions, which correspond to the West North Central and West South
Central regions defined by this analysis. Coastal areas in the Northeast from Maine south to New
Jersey and in the Northwest south to northern California have class 4 or higher resources.
The PNL study cited above provides estimates of state-level windpower potential. The report
presents the average wind electric potential for the 48 contiguous states (in GW) based on current
turbine technology (30 meter hub height) sited in Class 5 or above wind resources, and turbines sited
in class 3 or above resources (at 50 meter hub height). Figure IX-2 and Table IX-1 show PNL
estimates for the 12 EPA regions. After excluding land for environmental and economic reasons, 78%
of the class 5 and above resource is located in just 3 states (Montana, North Dakota, and Wyoming);
consequently, the EPA West North Central and Mountain regions contain 88% of these class 5
resources. These same regions contain 70% of the class 3 and above wind resource, while another
17% of class 3 potential resides in the West South Central region.
Seasonal Variation
In addition to regional variation in wind resources, seasonal variation in resources occurs. For
the most part, the maximum wind speeds occur in the winter and spring seasons with the minimum
speeds during the fall and summer seasons throughout most of the U.S. Many of the higher exposed
ridge crests and mountain summits in the eastern and western U.S. experience high wind resources
throughout the year. However, extreme wind, icing, and inaccessibility caused by poor weather in
regions such as the Southern Rocky Mountains, the Pacific Northwest, and the Great Lakes region
restrict the suitability of many of these areas for wind energy development. Another barrier to ridge
and mountaintop wind development is. aesthetic impact. Local terrain features can also cause wind
speed to vary considerably over short distances, especially in areas of coastal, hilly, and mountainous
terrain.
CONVERSION TO ELECTRICITY
Producing electricity from wind energy requires that conversion technology be matched with a
viable wind resource. Improvements in wind turbines and in wind resource assessment were
instrumental in the development of windpower during the 1980s, and further refinements are expected
to reduce the costs of capturing wind energy to provide electric power.
IX-4
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FIGURE IX - 2
Regional Wind Potential
1/ The electric potential is based on current technology (30 meter hub height)
sited in Class 5 wind or above wind resources.
2] Source: Elliot, D.L, LL Wendell, and G.L Gower. "U.S. Areal Wind
Resource Estimates Considering Environmental and Land-Use Exclusions."
IX-5
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TABLE IX - 1
REGIONAL WIND ELECTRIC POTENTIAL BASED ON CURRENT TECHNOLOGY ESTIMATES
EPA Model Region
New England
Mid Atlantic
South Atlantic
Florida
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
Total United States
30 Meter Hub Height,
Class 5 or Above Wind Resource
(GW)
1.3
0.3
0.5
N/A
0.4
22.1
N/A
0.7
36.6
1.1
1.7
1.7
67
50 Meter Hub Height,
Class 3 or Above Wind Resource
(GW)
10.7
12.5
2.7
N/A
20.5
619.0
N/A
221.0
273.0
51.0
7.0
9.0
1,267
Source: Elliot, D.L, LL Wendell, and G.L Gower. "U.S. Areal Wind Resource Estimates
Considering Environmental and Land-Use Exclusions.' Pacific Northwest Laboratory,
September 1990. Table 6, based on'reasonable exclusion scenario.' Note: Wind
electric potential is estimated in this report in GW equivalents; these capacity figures
are not, however, equal to nameplate capacity.
IX-6
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Conversion Technology
Wind power systems convert kinetic energy into electricity through the use of a wind turbine
which in turn drives an electric generator. An individual wind turbine can be used to provide on-site
power for a specific load or multiple wind turbines can be combined together into a wind farm for
larger scale power generation. Two basic wind turbine designs are currently in use: (1) the more
common horizontal-axis wind turbines (HAWTS) using either an upwind or downwind design with
typically 2 or 3 blades where the axis of rotation is parallel to the wind stream and the ground, and (2)
vertical-axis wind turbines (VAWTS) where the axis of rotation is perpendicular to the wind and the
ground. VAWTS are the hoop-shaped, or "egg-beater* turbines.
Many variations in design are possible for the HAWTS; over 50 different HAWT machines are
commercially available that vary both in size and design. For example, a yawing device, which
controls side to side motion, keeps the rotor oriented properly in the wind stream. Some HAWT
designs have a tail vane or rudder to control the yawing motion; others, typically the larger machines,
have active yaw systems controlled by microprocessors. VAWTS are similar in design and size,
ranging from 100 to 300 kW. In California, HAWTS represent more than 93% of current wind
generating capacity, while VAWTS account for the remainder. Nearly three-fourths of all blades have
been built from fiberglass, the remainder are built from either laminated wood or made from aluminum.
Almost all new turbines being installed in California use fiberglass blades.5
Turbine system measurements are comprised of two critical dimensions: rotor diameter and
tower height.6 Recommended tower height varies according to rotor diameter; towers can be
constructed from modular sections containing 10 to 20 foot modules. Wind system dimensions range
from less than one kW for electric water pumping systems to utility scale turbines of greater than one
MW. Examples of turbine configurations and dimensions are found in Figures IX-3 and IX-4.
Turbines produced for wind farms typically range in size from 18 to 600 kW, with the majority
being in the 100 kW range. Turbine manufacturers rate output (in kW) at an arbitrary wind speed for
comparative purposes. The actual capacity of a wind turbine, however, depends on site
characteristics and can be higher or lower than standardized ratings assigned by turbine
manufacturers. Therefore, kilowatt ratings for wind turbines are imperfect measures to compare
directly with conventional power plant capacity ratings. Rotor diameter and rotor swept area, which is
5 Paul Gipe, "Wind Energy Comes of Age in California,' May 1990.
6 A two- or three-bladed HAWT has a rotor diameter equal to the diameter of the circle swept out by the blades.
For VAWTS, rotor diameter is measured from the outside edge of one blade to the outside edge of the other.
IX-7
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FIGURE IX - 3
Wind Turbine Configurations
Rotor
diameter
Gearbox
Wind direction
for an
upwind rotor
Rotor
blade
Generator
Nacelle
> r*
-S ' If Wlm
Wind direction
lor a
downwind rotor
Fixed pitch
rotor blade
-Tower
Gearbox
Horizontal-Axis Wind Turbine
(HAWT)
Vertical-Axis Wind Turbine
(VAWT)
Source: Five year Research Plan, 1985 - 1990, Wind Energy Technology: Gaining Power from
Wind, p. 2.
IX-8
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FIGURE IX - 4
Altamont Pass Wind Turbines
Source: D. R. Smith, The Wind Farms of the Altamont Pass Area,' American Review of Energy, 1987,
12:145-83, p. 153.
IX-9
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proportional to the square of the rotor diameter, are much more reliable indicators of wind turbine
generation potential.
Capital costs (expressed in $/kW) and capacity factors also depend on the rated wind speed,
complicating comparisons among different wind turbines as well as comparisons against conventional
fossil fuel alternatives. For example, Fayette reports a 5% capacity factor in Altamont Pass compared
to an average of 20% for other makes of turbines in the Pass. However, the actual output per square
meter of rotor area (a measure of conversion efficiency) is only 19% below the average output of the
remaining turbines in the Pass. The discrepancy exists because Fayette rates its wind machines at
unusually high wind speeds.7
Siting and Resource Assessment
Because the energy contained in the wind increases with the cube of wind speed, areas with
the highest average wind speed offer the most potential for power generation. For example, a site
with average wind speeds of 16 miles per hour has almost 90% more available wind energy per unit of
area than a site with average speeds of 13 miles per hour, while a site with average speeds of 19
miles per hour has over 210% more available energy than a 13 miles per hour site. However, since
wind turbines can capture only a portion of this energy, the electricity generated by a turbine rises
approximately with the square of the annual average wind speed.8 Thus, turbine output is about 50%
higher at a 16 miles per hour site and about 110% higher at a 19 miles per hour site compared to a
13 miles per hour site.
In addition to average wind speed, the geography of an area is very important. Certain
geographical characteristics found in coastal, mountainous, and great plains regions can work
together to create conditions suitable for wind power. For instance, in California the combination of
cool ocean air and hot interior air generate pronounced differences in atmospheric pressure which
result in a diurnal flow of cool ocean air inland at certain times of the day. Natural breaks in the
Sierra-Nevada mountain range funnel this wind, creating ideal sites for wind power generation. Data
on expected daily and seasonal wind speed variation can help project developers evaluate the value
of the wind generation to the utility system as a whole. Recent research has also confirmed the
importance of micrositing or making more extensive wind measurements prior to siting a wind turbine;
7 D.R. Smitrv, The Wind Farms of the Altamont Pass Area," Annual Energy Review, 1987.
8 Don Bain, 'Issue Paper 89-40 Wind Resources," Northwest Power Planning Council, October 17, 1989.
IX- 10
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small changes in the position and height of a turbine can make a large difference in the wind resource
captured.
Wind resource assessment, or wind prospecting, is done in two stages. The initial stage of
assessment, macro-prospecting, has largely been done. Macro-prospecting entails the broad,
regional assessment of wind resources as defined by The Wind Atlas.9 The second stage of
resource assessment begins with preliminary wind prospecting and is followed by site specific
evaluations. To determine long term variations in the wind resource, preliminary prospecting involves
measuring wind speeds at a prospective site for a few years and evaluating the data against a nearby
location for which longer term wind data exist, such as an airport. The site specific evaluations entail
determining average wind speeds and direction by minute, hour and day and how these figures vary
across the site and at different heights. Since wind speed and direction is not uniform over all heights
at a specific site, and since the area swept by the rotor can span over 100 feet, this data is necessary
to accurately evaluate the wind regime and select an appropriate turbine, location and height. This
data can then be used to analyze the coincidence of the wind resource and utility peaking.10
Even when grouped in wind farms, turbines must be dispersed enough to capture wind
energy effectively. If the turbines are placed too closely together, the wind is not fully replenished
before it encounters the next turbine. The extraction of energy by upwind turbines causes 'array
losses,1 which can reduce energy production by as much as 15 to 20 percent. In the past, some
developers installed their turbines too closely together because of their poor understanding of
interaction effects, complex terrain, and inadequate micrositing practices, and experienced array
losses as a result. In addition, improper turbine siting induced turbulence that made downwind
turbines less reliable. In response, developers have tried to minimize array losses and turbulence
effects by increasing the scope of micrositing studies.
Resources Recovered
In 1990, 1360 MW of installed capacity produced 2100 GWh of electricity. At rated capacity,
therefore, the capacity factor for wind turbines currently averages about 18%, a figure that has been
steadily rising as older machines are replaced by newer models and as resource assessment
continues to improve. Pacific Gas and Electric (PG&E) recently reported that the capacity factor of the
734 MW of turbines in its service territory at Altamont Pass increased from 9% in 1983 to 16% in 1988
9 The Wind Energy Resource Atlas of the United States. Prepared by Pacific Northwest Laboratory for the U.S.
Department of Energy, October, 1986
10 Information obtained from conversation with Robert Lynette, August 22, 1990.
IX- 11
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due to (in order of importance) increased reliability, more efficient turbine designs, and improved siting
evaluation and implementation. Over 97% of wind energy output in the U.S. is captured in California,
where HAWTs dominate the market.11 California windpower generation is concentrated in five
areas: Altamont Pass, Pacheco Pass, San Gorgonio Pass, Solano County, and Tehachapi Pass. The
most productive wind power stations are located in San Gorgonio pass, where wind turbines have
consistently exceeded 30% capacity factors.
Current Economics
Total costs of wind energy system deployment are comprised of the following costs: project
lead time, land acquisition, system components and installation (capital costs), operation, and
replacement. California's wind farms consist of first and second generation technology. First
generation machines of the early 1980s, mainly of U.S. design, tended to be small-scale, lightweight
designs based on aerospace technology. The representative turbine was rated at 50 kW and cost
$2.220/kW installed. Second generation machines, installed from the mid-1980s through the present,
are largely of European design. These turbines are medium-scale, averaging 300 kW, heavyweight
machines whose conservative engineering largely overcame the lack of understanding regarding
structural and aerodynamic stress. Their cost is currently about $1,000/kW - $1,200/kW installed.12
The project lead time costs include the cost of a wind resource assessment, which could
involve up to 3 years of site data collection and developing additional micrositing data after a resource
has been identified. The measurements are necessary to determine the potential energy production
and cost-effectiveness of a potential site. Also, a 12 to 18 month micrositing, engineering, and
permitting period is needed after resource assessment and before construction. Typical construction
time from ground breaking to turn-key operation for a representative stand-alone turbine system is 1 -2
weeks. Construction of most wind farms would be expected to take fewer than 6 months.
The total cost of a well researched resource assessment is, as a rule of thumb, $10/kW, or 1%
of current total installed costs. The detailed evaluation includes setting up about seven towers, seven
data loggers and fourteen anemometers. The cost of the equipment is approximately $21,000. The
cost of maintaining the equipment, downloading and analyzing the data is approximately $50,000. An
upper bound estimate for maintenance and data analysis would be no more than $100,000, bringing
11 Nancy Rader, Power ol the States, Appendix 1, Table 2.
12 Don Bain, "Issue Paper 89-40. Wind Resources,' Northwest Power Planning Council, October 17, 1989. See
also Electric Power Research Institute. Technical Assessment Guide: Electricity Supply - 1989. Volume 1, Revision
6, September 1989.
IX- 12
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the high cost estimate for resource assessment to $15/kW. The equipment used in the first detailed
site assessment can be used for further assessments.13
Land acquisition costs vary according to potential alternative uses of a site and zoning
requirements. The exact amount of land required for a multi-megawatt turbine system is determined
by many factors, which include on-srte wind characteristics, the geologic and natural features of a
specific site, and the individual turbine capacity. Wind sites must include sufficient land for
construction of facilities, routing transmission lines, proper spacing of turbines, as well as a buffer of
extra land to ensure the accessibility of the wind resource, since nearby buildings, billboards, trees,
etc. could shield turbines from available wind. Since wind systems require only about 5% to 10% of
the actual land area, agricultural and grazing uses are typically compatible with wind installations.
Wind system component and installation costs include rotor, drive-train, tower to support rotor
and drive-train, turbine and support controls, and balance-of-system (BOS) costs. The nacelle
enclosure, which contains the turbine's generator, transmission, and control system, accounts for
about 35% of the total capital cost. The turbine tower, the rotor blades, and the down tower box
account for about 10% each. The remaining 33% are non-machine costs, of which 18% are for
permits, land use, warranty and insurance, and 15% are for roads, power lines, and other
infrastructure. Average construction costs have dropped from $3,100/kW of capacity in 1980 to
between $850 and $1,400/kW, with annual O&M costs between 1 0/kWh and 2 0/kWh in 1989.14
PG&E reports current installed costs of $1,100/kW, O&M costs of 1 0/kWh and a capacity factor of
25%.15
The BOS charges include costs .of system infrastructure: interconnection facility, roads and
service buildings, and contingency fees. BOS costs vary according to site, turbine, and project size.
Where transmission lines are required to connect remote wind resources to the grid, the costs of
building transmission capacity would also be included in the capital costs of wind development. A 115
kilovolt transmission line that could transport electricity from a 150 MW power plant would cost about
13 Information obtained from conversation with Robert Lynette, August 22, 1990.
14 The Potential of Renewable Energy, Interlaboratory White Paper prepared for the Office of Policy, Planning,
and Analysis, U.S. Department of Energy, (Golden, Colorado- Solar Energy Research Institute, March 1990), p. F-
10
15 D.R Smith, M.A. llyin, and W J Steeley, "PG&E's Evaluation of Wind Energy," 1989.
IX- 13
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$110,000 per mile.16 For wind systems, the cost of transmission line additions would be spread
over the wind farm and not an individual turbine.
Operation and maintenance (O&M) costs include regular turbine inspection, blade cleaning
and lubrication. Some blade designs lose up to 15% efficiency due to dirt and bug accumulation.
Periodic overhauls of rotor, gearbox, and generator and periodic component replacement are also
included in the operating costs. Replacement costs in the 8th and 20th year of turbine operation are
estimated to be $27,000 to $40,000. The cost includes $17,000 to $23,000 for blade replacement with
the remainder for replacement and overhaul of other system components. A levelized replacement
cost for a 13 mph site is approximately 0.5 C/kWh to 0.9 c/kWh.17 Table IX-2 displays a summary of
windpower technology cost estimates.
The costs do not include energy storage or backup options. The availability of cost-effective
storage options, as well as system options to help firm or shift windpower output could promote
widespread deployment of wind energy systems. At present, few cost-effective storage options are
available for extensive use. Chapter X discusses these options in some detail, and examines the
economics of hybrid wind-fossil energy systems.
In addition to quantifiable costs, wind electric generation incurs some social costs such as
increases in area noise levels, interference with television and radio reception, occasional bird deaths,
and negative aesthetic impacts in some areas. The noise from wind turbines includes the sound of
the blades hitting the air, as well as the sound of gears turning and the hum of the generator. The
noisiest turbines have been described as creating a high-pitched aerodynamic whizzing sound, but
most turbines make very little noise more than ambient wind noise.
Intermittent Generation and System Operations
Unless smoothed or otherwise mediated by a storage technology, the intermittent generation
from wind turbines can pose some technical problems for the utility system. The intermittent nature of
wind generation makes it difficult for utility system planners to calculate a constant flow of power from
the source to be included in balancing instantaneous power supply and demand. Windpower's
intermittent contribution to the electricity grid may be limited by technical constraints governing
16 This figure is used in "Geothermal Resources" Northwest Power Planning Council Staff Issue Paper, October
1989, p.27
17 J.M. Cohen, T.C. Schweizer, S.M. Hock, and J.B Cadogan, "A Methodology for Computing Wind Turbine
Cost of Electricity Using Utility Economic Assumptions,' 1989.
IX-14
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TABLE IX - 2
WINDPOWER TECHNOLOGY COST MATRIX
PROJECT LEAD TIME 1/
Resource Assessment
$10/kW, or
$71,000
SYSTEM COMPONENTS 21
~ Total System Costs
-- Rotor, Drive-Train, Tower, Turbine, and
Support Controls
- Balance of System Costs (BOS)
- Interconnection Facility, Roads and
Service Buildings, Contingency Fees
$1,013/kW
$750/kW
$263/kW
OPERATING AND MAINTENANCE COSTS 1/
- Turbine Inspection, Blade Changing,
Periodic Overhauls, Component
Replacement
Component Replacement Costs 3/
- Blade Replacement
- Replacement of Other Components
0.5C - 2c/kWh
$23,000
$17,000
1/ Cost estimates for resource assessment and operations and maintenance were
obtained from Robert Lynette dunng a conversation on August 22, 1990.
21 Source: Electric Power Research Institute. Technical Assessment Guide: Electricity Supply -
1989. Volume 1, Revision 6. September 1989.
3/ Source: 'A Methodology for Computing Wind Turbine Cost of Electricity Using Utility Economic
Assumptions" by J.M. Cohen, T.C. Schweizer, S.M. Hock, and J.B. Cadogan, 1989.
IX- 15
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operating and reliability concerns that limit a utility's ability to incorporate intermittent generating
sources. Wind plants produce alternating current (AC) power, but require frequency regulation
electronics because windpower turbines produce variable frequency current. These frequency
regulation systems are subject to stress, reduced reliability, and limit the maximum power available
from wind. Recently developed solid state power conversion technology can allow a wind turbine to
generate as much power as possible, convert the variable frequency power to AC, and supply reactive
power to compensate for the natural induction of wind turbine generators.
Aspects of interconnecting wind plants to utility transmission systems in California have been
less problematic than anticipated, primarily because almost all windpower in California is supplied to
the state's two largest utilities. The utilities' large, diverse power systems are better able to
accommodate substantial increments of power rising and falling with the wind. In contrast, less
extensive utility systems with constrained generating and transmission capacity would be less able to
accommodate the power fluctuations that would accompany using windpower to supply a significant
portion generation.
Beyond the technical problems encountered when accommodating wind energy into electricity
supply systems, the value of intermittent windpower is not as high as "firm" energy from fossil fuel
sources. Because of the emphasis on system reliability, utilities do not typically count windpower as a
resource that can replace conventional capacity. Chapter X explores the economics of intermittent
renewable resources and examines hybrid options that can enhance the value of windpower
generation.
Land-Use Conflicts
The potential impact of land-use and zoning laws on wind system siting will largely depend on
the ownership of the land being sought for development. Land-use conflicts not only involve potential
competition from higher-valued uses, but they also confront restrictions based on nuisance factors,
building-scale requirements, and on-site environmental impacts. Nuisance factors that could restrict
the use of suitable land include turbine noise, dust and other negative impacts on flora and fauna in
surrounding areas. The size of a wind turbine project can also be limited by building and zoning
regulations that protect aesthetic values. Many potential wind resource areas are in national forests
and wilderness areas that are precluded from development.
The federal government controls large tracts of undeveloped land that hold some of the most
favorable sites for wind turbine system development. For example, the U.S. government holds title to
more than 40% of the land in the 11 contiguous western states, states which also contain over 60% of
IX-16
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the best wind sites.18 Both the Bureau of Land Management (BLM) and the United States Forest
Service (USFS) are given broad authority to manage these lands according to Federal policy, which
dictates that all uses of such land must serve the national interest and comply with multiple use and
environmental regulations. However, Congress can designate some BLM lands as permanent
wilderness areas, which would preclude all development activities. Land-use and zoning policies on
the federal, state, and local level can also impede wind system deployment. A developer's ability to
gain access to land regulated by state and local authorities will be affected by long-term
comprehensive land-use plans and the mechanisms available to developers to lease or acquire that
land. State land-use regulations can restrict or encourage particular land-use options.
Remote Transmission Access
Transmission costs pose a potentially large obstacle to windpower development. When good
wind sites are far from existing transmission lines, lines must be extended to access the power from
these sites. Building transmission lines from the wind site to the existing grid involves additional
expenditures, increasing the capital costs of windpower. Depending on terrain and design capacity,
high power transmission lines cost between $100,000 and $500,000 per mile.19 These costs add
roughly $80/kW for a 100 mile line. In light of the high cost and various obstacles to siting and
building transmission lines in the U.S., transmission could potentially impede windpower development.
Small power producers, such as qualifying facilities (QFs) under PURPA, face the same regulatory
maze that a utility faces when building additional transmission facilities. Given the choice between
building on a remote site or close to existing transmission, a utility will likely choose the site close to
existing transmission capacity. If QF developers only have access to the remote site, adding the cost
of additional transmission lines increases their capital costs. The additional expense makes remote
siting primarily an economic issue, although institutional issues such as permitting, financing, and
eminent domain can also hinder transmission capacity development.
A slightly different transmission limitation has arisen in the wind regions of California, where
windpower development has strained the capacity of existing transmission lines. Upgrading a
transmission line is less expensive than building new lines, but conflicts can emerge over the
18 According to the recent PNL analysis, the 11 western states have 41 GW of class 5 potential wind resources
that could be developed, out of a national total of 67 GW (see Table IX-1). About 340 GW of class 3 wind resource
could be developed in these western states, out of a nationwide total of 1,267.
19 See "Geothermal Resources" Northwest Power Planning Council Staff Issue Paper, October, 1989, p. 27
($110,000 per mile for a 115 kilovolt line that could serve a 150 MW power plant); and Power Plays, by Susan
Williams and Kevin Porter, Investor Responsibility Resource Center, 1989, p. 170, ($520,000 per mile for a 230
kilovolt line that serves 600 MW of capacity)
IX-17
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allocation of upgrading costs between utilities and windpower developers. At issue is the level of
'system-wide* benefits that would occur as a consequence up transmission upgrade, which utilities
(and eventually ratepayers) must pay to the OF for its upgrade project.
EMERGING CONVERSION TECHNOLOGIES
Wind machines have progressed through two generations of development, and are now
entering a third. A public/private research, development and demonstration program is continuing to
improve all aspects of wind electric generation technology.
Costs and Performance
A third generation - so called next generation or advanced generation turbines - is currently
being developed using improved understanding of aerodynamics to develop lighter weight and more
efficient designs. These machines are larger in size, at 150 to 600 kW, and are projected to cost
roughly $650/kW. The third generation wind turbines are still in their R&D phase. However, U.S.
Windpower (USW), Electric Power Research Institute (EPRI), and several utilities have developed and
are testing an advanced wind turbine program, scheduled to run through 1993. The program includes
two USW model 33M-VS (variable speed) turbines and an advanced power electronic converter. The
turbines each have rotor diameters of 33 meters (108 ft), and generate 400 kW. One of these turbines
was erected in Altamont Pass, California in June 1989. The design is expected to produce 800
MWh/year at a life cycle electricity cost of about 5 c/kWh.
Figure IX-5 shows a SERi estimate of the impact of future technology improvements on cost of
electricity (COE) expressed as a fraction of current costs. Various technological innovations
discussed below have the potential to reduce O&M costs, boosting energy output and decreasing
overall system costs. According to SERI, these technological developments could reduce levelized
costs to between 3 c/kWh and 4 c/kWh by 2010.
Potential Technology and Multiple Pathways
The primary focus of the DOE/EPRI/USW R&D program is to increase the efficiency and
reduce the capital costs of wind turbines. The advanced wind turbine system would combine a series
of technical improvements developed in the laboratory and field over the past several years to lower
costs of wind systems, improve system durability, and increase power output. This turbine design
IX- 18
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FIGURE IX - 5
Future Technology Improvements
Operating Strategies
Design Toots
Advanced Airfoils
Array Spacing
Improved Reliability
Improved Manufacturability
Current Technology
Near-Term
Advanced Technology
Source: The Potential of Renewable Energy, Interiaboratory White Paper
prepared for Office of Policy, Planning, and Analysis, U.S. Department of Energy
(Golden, Colorado: Solar Energy Research Institute, March 1990).
IX- 19
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R&D is expected to lead to major efficiency improvements from the current 15% - 20% up to
30% - 35%.
The major objectives of the R&D program are: to develop advanced hub designs and
materials which reduce stress and fatigue; to improve blades which will boost energy capture and
suffer less degradation from dust and insect buildup; to refine power electronics to ensure that power
quality meets utility standards; to incorporate adaptive controls for higher energy capture; to
introduce variable speed turbines and generators; to optimized drive-trains (The drive-train includes
the gearbox and generator); and to improve micrositing. These enhancements will be incorporated
into a new generation of 200 kW to 600 kW wind turbines that should operate more reliably and
efficiently at variable wind speeds with a generation cost (assuming annual average wind speeds of 13
mph) of about 5 c/kWh. This target would represent about a 40% improvement over current designs.
The gains in efficiency in variable wind speed operating conditions would make much more land
suitable for windpower development.
The variable speed turbine employs a power electronic converter between the generator and
the utility line. This allows the rotor and the generator to speed up with stronger winds. The
increased energy is then converted into more electricity without increasing strain on the drive-train.
Variable speed generators can maintain peak efficiency over a wider range of wind speeds by
controlling generator speed. They further help to reduce transient and dynamic loads that are
transmitted from the rotor through the drive-train to the turbine tower. Transient loads are stresses
that occur during start-up, shutdown, and during turbulent wind conditions; dynamic loads are
transmitted from the rotor through the drive-train dunng normal operation. These advantages may
help designers to alleviate the serious component fatigue problems encountered by existing wind
systems, increasing component lifetime by up to 25 percent. Variable speed generators are generally
more complicated and expensive than constant speed generators. However, increased energy
capture, estimated at 15 to 20 percent for large turbines, should reduce the cost of energy by 10 to 15
percent.20 Researchers at Sandia National Laboratories (SNL) are working to better understand how
the constantly changing aerodynamic forces and the subsequent structural responses affect variable
speed operations.
Structural fatigue problems may be alleviated through the use of advanced materials such as
fiberglass composites. Research is being conducted to understand the response of both conventional
Solar Energy Research Institute, "Variable Speed Operation of Wind Turbines: Impact on Energy Capture
and Economics," by S. Hock and P Tu. presented at the ASES 1986 Annual Meeting and Passive Conference,
June 8-14, 1986
IX-20
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blade materials, such as aluminum for VAWTS and wood epoxy for HAWTS, as well as newer
materials. Field tests are being conducted by SNL to study fatigue damage of sample materials on
commercial machines. SNL's research also includes fracture analysis to predict the growth of blade
cracks.
In 1988, SERI began collecting the world's first simultaneous measurements of wind inflow,
pressure, strain, power output, and other characteristics of a rotating HAWT. The research focuses on
a fully instrumented HAWT measuring 10 meters in diameter and rated at 8 kW. Measurements are
fed to a data acquisition device mounted on the rotating hub, while a video camera allows researchers
to observe the interplay of airflow and the forces that create stress. Small tufts attached to the blade
surface indicate the presence of smooth or turbulent flow, while color changes in liquid crystals
applied to the blades show the effects of varying airflow forces.21
This "combined experiment" will lead to greater understanding of the aerodynamic forces at
work during wind turbine operation. Preliminary results are still being analyzed, but this unique
experiment is expected to reshape the basic assumptions of wind turbine aerodynamics. Actual
measurements of aerodynamic forces and structural response will soon be available for improved
computer models and design codes. The experiment is also expected to validate the performance of
advanced components such as SERI's specialized airfoils.
Decreases in windpower costs may be achieved through the development of a variable speed
rotor that uses power electronics and a stall controlled rotor with aerodynamic controls. Development
of the stall control rotor depends on research into overspeed control, smaller drive-train components,
and lowering thrust loads as a result of better stall control. Research into stall behavior may resolve
technical problems related to the application of variable speed generators to wind turbines.
Preliminary estimates indicate that the variable speed rotor will not alter the installed cost of the overall
system, but could increase annual energy output by 56% while reducing operations and maintenance
(O&M) costs by about 0.5 c/kWh. The stall control rotor will reduce overall system costs by
approximately 12%, and increase annual energy output by 49%, with a 0.6 0/kWh reduction in annual
O&M costs.22
SERI has also identified 'advanced' technology improvements, targeted to appear around the
year 2010, that can reduce costs and increase windpower penetration. These technologies will
91
Solar Energy Research Institute, "Windpower... Today's Energy Option," April 1989.
22 Susan M. Hock, Robert W. Thresher, and Joseph M. Cohen, "Performance and Cost Projections for
Advanced Wind Turbines," 1989.
IX-21
-------
incorporate currently unexplored subsystem concepts to increase energy capture from individual wind
sites, potentially reducing the costs of windpower to about 3 c/kWh. Possible features of the
advanced technology include: advanced airfoils, innovative aerodynamic controls, fatigue tolerant
rotor designs, advanced articulated blade/hub configurations, adaptive controls, advanced generation
concepts, new materials for all components, optimized wind plant layout, and parts designed for easy
manufacture, installation, and maintenance.23
MARKET ASSESSMENT
Table IX-3 shows the DOE/SERI and EPA scenarios for windpower. In the DOE/SERI report,
the costs of windpower generated at excellent and outstanding sites are assumed to become
competitive with the variable costs of natural gas-fired generation between 1995 and 2000 in the BAU
scenario, and generation from good sites becomes competitive with gas by 2005. These favorable
economics are accelerated under the policy scenarios: by 2010 generation from outstanding sites
becomes competitive with the variable costs of coal-fired generation.
If windpower indeed becomes competitive with coal-fired baseload generation, then the
economic comparison between fossil generation and wind will be less sensitive to the seasonal and
daily variation of windpower. In the interim, however, some of the expected wind generation would
occur during seasons and periods of the day when the marginal fuel is not exclusively gas. The
assumption that windpower would always displace gas overstates the true avoided energy cost from
wind generation.
Given this observation, the DOE/SERI BAU projection of 22% annual average growth in wind
power generation between 1988 and 2000, and 20% annual average growth between 1988 and 2010,
appears optimistic.24 The EPA Base Case and Enhanced Market scenario were constructed using a
model of regional windpower cost, which is described in Appendix B. The Enhanced Market scenario
assumes that the barriers identified above are addressed (leading to greater land areas available for
windpower), and that intensified RO&D would lower wind turbine costs.
23 Susan Hock and Robert Thresher.,'Performance and Cost Estimates for Advanced Wind Turbines," January
1990
24 The impact of fuel paces on the SERI projections ts explored in The Sensitivity of Wind Technology
Utilization to Cost and Market Parameters,' by Henry M. Oodd. Susan M. Hock, and Robert W. Thresher in the
AWEA Windpower '90 Proceedings. September 1990. Variations of 50% in fuel costs were found to have order-of-
magnitude impacts on near-term windpower penetration rates
IX-22
-------
TABLE IX • 3
WINDPOWER SCENARIOS
Scenario
DOE/SERI
Business as Usual
Intensified RD&D
National Premiums
EPA
Base Case
Enhanced Market
Capacity
2000
(MW)
8,800
15,000
17,200
4,900
10,600
Generation
2000
(GWh)
20,500
38,000
41,000
10,100
26,500
Capacity
2010
(MW)
39,500
78,400
95,000
20,900
57,400
Generation
2010
(GWh)
99,500
223,400
240,900
48,600
141,800
1990: 1,400 2,100
The recent PNL study provided the potential wind resource data used in the EPA market
assessment. The EPA Base Case and Enhanced Market scenario assume that regional windpower
resource development is proportional to the cost differential between windpower and fossil energy
sources. The EPA Base Case for 2000 assumes the DOE/SERI BAU capital costs of $1,000/kW and
operating costs of 1.2 c/kWh, which fall to $965/kW and 0.9 c/kWh in 2010. The Enhanced Market
scenario for 2000 assumes the DOE/SERI RD&D scenario capital costs of $950/kW and operating
costs of 1.0 c/kWh, falling to $850/kW and 0.8 c/kWh (based on turbines operating in 13 mph average
wind speed regimes).25 A capital charge rate of 10% was used to compute levelized costs for
windpower, which assumes that developers would be able to secure longer term financing in the
future compared with current practice. Regional capacity factors were assumed to increase over time,
as a result of increased reliability and improved siting practices. Capacity credits were set at 50% of
the regional capacity factor in 2000, and 67% of the regional capacity factor in 2010, reflecting the
increased attention to utility peaking needs when siting wind turbines.
25
Please note that because windpower costs have declined rapidly in recent years, it is likely that estimates of
capital and operating costs in future years reported here are already dated.
IX-23
-------
Tables IX-4 and IX-5 give the air pollution prevention and cost results of the EPA scenarios. In
the Base Case, annual windpower generation increases at an annual average growth rate of 17%
between 1990 and 2010, adding 46,000 GWh per year from current levels. Because of vast wind
resource potential, the West North Central and Mountain regions account for the majority of the
generation increase. In the Enhanced Market scenario, generation from wind increases by 140,000
GWh between 2000 and 2010, approximately 3 times the Base Case growth in generation between
1990 and 2010, again concentrated in the North Central and Mountain regions.
Costs
Despite partial capacity credits, the seasonal pattern of windpower generation in most regions
made avoided costs for windpower lower than for other renewables: about 3.0 0/kWh (2000) and 3.7
C/kWh (2010) in the Base Case and 2.9 c/kWh (2000) and 3.5 0/kWh (2010) in the Enhanced Market
scenario. The low avoided cost continued to place windpower at a small cost disadvantage in many
regions; however, in the Northeast, Southwest, and California, windpower was less expensive than
the fossil fuel electricity it displaces in 2010 in both scenarios. Chapter X describes how fossil-fuel
hybrid options can increase the value of windpower generation as measured by utility avoided costs.
Air Pollution Prevented
Substantial amounts of air pollution are prevented from increased windpower generation
between 1990 and 2010 in the Enhanced Market scenario. Over 600,000 metric tons of S02 could be
freed for the allowance market, and almost 570,000 metric tons of NOX would be avoided. Windpower
in the Enhanced Market scenario could displace 135 million tons of CO2 emissions annually by 2010.
Because of the geographic distribution of windpower and the assumed seasonal and daily
operating patterns, windpower tends to displace more coal-fired generation at the margin than other
renewable electric technologies examined in this report. As seen on Table III-3 (Chapter III),
windpower could displace between 940 and 965 kilograms of CO2 per MWh generated, and could
displace about 4 Kg/MWh of NOX from fossil fuel plants. However, these estimates do not take into
account many of the more sophisticated utility system operating constraints. For example, utilities
accepting large quantities of intermittent windpower may have to increase "spinning reserves," which
are operating plants that provide little or no power to the grid to accommodate fluctuations in load.
More sophisticated production simulation models would help verify the emission reduction potential of
windpower generation in specific utility systems.
IX-24
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CHAPTER X
INTERMITTENT TECHNOLOGY AND HYBRID/STORAGE OPTIONS
This chapter describes how intermittent renewable resources can be integrated into the 'grid,'
or electric supply systems. Intermittent resources include hydroelectric, solar, and wind. Discussions
of intermittent resources tend to focus on the 'capacity credit' of renewable generation options.
Capacity credit (sometimes called contribution to reserve margin) is the fraction of rated (nameplate)
capacity that utilities can count on as firm' resources during peak demand periods. In this context,
firm refers to a level of reliability (or availability) equivalent to conventional fossil units. A related
concept is dispatchable capacity, which refers to the level of control a utility has over the power
output of a generating unit. Intermittent renewable generating facilities are neither dispatchable nor
firm by conventional utility definitions.1
Because of the emphasis on reliability, utilities do not usually grant intermittent renewable
resources capacity payments when negotiating power purchase agreements with Qualifying Facilities
under PURPA. Likewise, intermittent renewable generation may be at a disadvantage in competitive
procurements because the methods used to evaluate bids are structured so that only firm capacity
bids will be chosen. Current utility practice may inhibit the emergence of hybrid renewable or storage
options that have at least some capacity value when considered in the context of the entire system.
Many options exist to make intermittent resources firm from a utility standpoint. The solar
thermal/natural gas hybrid is an example of such a system, but it is only one of the possible
configurations. The multitude of other configurations can be divided into supply options, demand
options, and storage options.
SUPPLY OPTIONS
Supply options use other generating units on the grid to compensate for the variable output of
an intermittent resource. These can be further divided into renewable/renewable options,
renewable/fossil options, and renewable/system options.
1 Hydropower is somewhat different. Hydropower is dispatchable (controllable in the short run) but not firm
because it can be limited by the amount of water stored in the watershed. Because historical river flow records
exist, hydroelectric projects are often rated in under "adverse flow" conditions.
X- 1
-------
Renewable/Renewable Options
One way to boost renewable capacity credit is to geographically disperse the renewable
generating stations in order to minimize the potential that all stations would not be operating at the
same time: The probability that several dispersed PV collectors would be under cloud cover at the
same time in a large area is lower than the likelihood that one centralized plant would be covered with
clouds. Another option would be to combine several types of renewable resources, such as wind and
solar, in order to take advantage of inverse probabilities and complementary output patterns. A recent
analysis conducted by Pacific Gas and Electric suggested that a combination of wind energy and
solar energy would provide a good fit to daily patterns of utility demand in California. These 'portfolio
approaches' would imply some capacity credit for the total renewable generation, whereas each
individual station might have little or none.2 Such options would be especially valuable when utilizing
resources that tend to inversely vary. For example, if windy periods coincide with cloudy days, then
windpower could help to firm the availability of solar thermal or PV. Another option would be to use
biomass derived liquid or gas fuels to run backup thermal systems.
Wind and hydroelectric capacity are especially complementary, since the hydrosystem can
provide storage as well as firming capacity, and hydroelectric generation is especially responsive to
variable loads. One such system was proposed by the Bureau of Reclamation in the Department of
Interior in Medicine Bow, Wyoming. The daily and seasonal pattern of the wind resource fit well with
the utility load and the seasonal output of the hydroelectric system.3 Although the analysis indicated
that such systems would be economically viable, technical problems were encountered with the two
multi-megawatt turbines installed in 1982, and the project was abandoned during the mid 1980s.
Renewable/Fossil Options
Fossil fuel capacity can be used to compensate for intermittent renewable resources. Grid-
connected options can be either bundled or non-bundled.4
2 See "Wind Energy Resource Potential and the Hourly Fit of Wind Energy to Utility Loads in Northern California"
by D.R. Smith, in Windpower '90 Proceedings, (Washington, DC: American Wind Energy Association, 1990)
See Wind-Hydroelectric Energy Project - Wyoming, by the U.S. Department of Interior Bureau of Reclamation,
August 1982.
4 Non-grid connected (stand-alone) renewable electric systems are sometimes combined with fossil fuel backup
generation or storage technologies to provide steady power output.
X-2
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Bundled Systems. Bundled systems are either physically connected or else use a dedicated fossil
fuel unit to provide backup for a renewable energy source. For systems that involve thermal
/
conversion, fossil fuel backup can be integrated into the conversion system to provide heat. For
example, solar thermal hybrid plants use natural gas to heat the transfer fluid during cloudy periods.5
Another configuration for solar thermal is combined cycle. The 4.9 MW Solarplant One parabolic dish
plant in California has been modified with exhaust heat recovery exchangers from two 1 MW diesel
generating sets. The turbine generators can be powered by solar-generated steam or steam
generated from the heat remaining in diesel engine exhaust.6
Other bundled systems include dedicated fossil backup capacity that provides generation
when intermittent resources are not available. For example, fuel cells or diesel or gas turbine
generators can be built alongside of solar or wind generating stations. The expense of building
redundant capacity at the same scale as the intermittent renewable capacity often does not justify
such an approach. However, capacity payments given by utilities to renewable energy developers
may be based on the rating of the fossil-fuel backup generator. Such a payment would understate
the value to the utility of the intermittent capacity in some cases.
Non-Bundled System Options. Non-bundled options use other generating units in the utility system
to compensate for intermittent resources. This is how utilities normally accept intermittent generation
without planning specific capacity additions, but the amount of available backup is limited by the
current generation mix. In this context, however, a non-bundled option refers to building fossil
capacity to compensate for intermittent renewables, but choosing specific capacity types and sizes
based on system reliability concerns rather than arbitrarily scaling the unit to firm the renewable
capacity to 100% of its nameplate rating. Decoupling the backup capacity requirements from the
needs of a specific renewable energy system may have economic and operational advantages.
A recent analysis conducted for U.S. Windpower illuminates this point. Taking into account
the Sacramento Municipal Utility District (SMUD) power system and the statistical pattern of windpower
output, the analysis showed that a 100 MW windfarm combined with a 60 MW combustion turbine
(operating at 4% capacity factor) would have the same system reliability (as measured by loss-of-load
probability) as a 100 MW combustion turbine. Thus, U.S. Windpower could build a dedicated 60 MW
turbine in order to qualify for a full capacity payment for the 100 MW windfarm. In fact, U.S.
An example of a non-intermittent bundled system is a configuration that uses low-temperature geothermal
resource to provide heat for boiler feedwater as a way to reduce fossil fuel requirements.
6 See William Stine, Progress in
(SERI/SP-220-3237) June 1989, p. 8
6 See William Stine, Progress in Parabolic Dish Technology published by the Solar Energy Research Institute
X-3
-------
Windpower submitted bids with and without the backup capacity, and SMUD determined that they
could supply the backup power more cheaply through other units and bulk purchases: the non-
backup configuration was preferred. U.S. Windpower and SMUD are now negotiating the non-backup
power contract.
The Northwest Power Planning Council (NPPC) has been considering proposals to "firm" the
hydropower output in the region by adding natural gas capacity as an alternative to building new
baseload coal plants. Again, the overall reliability of the system, not the specific attributes of individual
hydropower sites, determines the value of such options.7
DEMAND OPTIONS
Two demand-side management (DSM) techniques could be used to help integrate intermittent
renewable electric generation. They are peak shaving, which attempts to limit the maximum demand
level (e.g. through offering interruptible service) or load shifting, which attempts to shift part of the
maximum load before or after the system peak period (e.g. through thermal storage). These
strategies are already valuable for utilities trying to defer capacity construction, but may have added
value if they could help control demand as a way to compensate for intermittent renewable supplies.
Commercial buildings can use thermal storage in order to avoid paying high peak demand
rates for air conditioning load. In areas where maximum windpower output predictably lags or leads
system peak hours, thermal storage at the point of end use would allow windpower to reliably serve
these loads. For example, the maximum daily output of windpower at the Altamont Pass in California
lags the utility peak load by several hours. Load shifting strategies could increase the value of wind
generation in such a circumstance.
Some utilities offer interruptible service to customers (at lower rates) in order to reduce loads
when unpredictable demand spikes and/or forced outages strain existing capacity. The value of
interruptible service may be higher when intermittent generation is part of the generation mix (although
the frequency of interruption may be higher).
These strategies offer utilities the opportunity to influence demand as a way to compensate for
predictable or unanticipated limits on supply; such DSM options can also provide utilities with another
instrument to help accommodate intermittent renewable generation. While utility planners have
7 See "Better Use of the Hydropower System" Staff Issue Paper 89-37 by the Northwest Power Planning
Council, October 16, 1989.
X-4
-------
traditionally viewed intermittent generation as an additional risk to providing reliable supply,
consideration of emerging demand-side options could encourage a more economic balance between
intermittent generating resources and fluctuations in electric demand. The evolution toward integrated
resource planning recognizes that the distinction between electricity demand and supply is not well
defined, and that the risks of supplying reliable electricity services may be shared by controlling both
the demand and supply of electric power.
STORAGE OPTIONS
Storage options can increase energy value, but they reduce net energy production because
no perfect electric storage medium exists. Thus, the economics of storage require that the increased
energy value (from increased reliability or from shifting power output to system peak load hours)
compensate for the storage cost and energy losses. Current storage options include conventional
and pumped storage hydro, batteries, compressed air, flywheels, and thermal storage. The availability
of cost-effective storage options compatible with utility systems and renewable resource profiles could
promote widespread deployment of intermittent generation. At present, few cost-effective storage
options are available for extensive use.
Conventional and Pumped Storage Hydro
As discussed earlier, conventional storage hydroelectric facilities can store intermittent
renewable generation. This occurs because the hydroelectric output can be reduced by the amount
of renewable generation provided, storing potential energy in the water that would otherwise turn the
hydraulic turbines. This form of storage can be used with solar energy or windpower. Pumped
storage hydro plants capitalize on the difference between base load and peak load generating costs
by using cheap base load electricity to pump water up behind the dam, which in turn is released to
generate power during higher demand periods. However, about 30% of the energy is lost in the
process. Because the pump cycle typically occurs during the night, pumped storage facilities are
most compatible with windpower.
An example of pumped storage potential exists in California, where the Attamont wind farms
produce their daily maximum output about eight hours after the daily utility peak need. A small
pumped storage hydro system could be constructed in the Pass, where there is suitable topography
and water available. This would enable the wind energy captured during the night to be used during
the following peak afternoon hours. Other hydroelectric storage strategies might also come into play
when the utility has discretionary hydroelectric capacity. For example, very hot afternoons in
California, which increase peak electric loads from air-conditioning, are almost always followed by
X-5
-------
windy evenings. It may be possible to increase hydroelectric plant output during the day while relying
on increased wind farm output later that night to meet demand, thus reducing the need to deplete the
reservoir further.8
However, the storage option feasible for Altamont Pass is site specific and may not be a viable
option for other areas. Total pumped storage resources, which consist of developed, under
construction, and projected pumped storage systems, are located in 11 of the 12 regions defined by
this analysis. Table X-1 displays regional pumped storage capacities. The South Atlantic, Mid-
Atlantic, West Mountain, and California regions combined contain approximately 60% of total pumped
storage resources, and projections for new pumped storage plants in West North Central and
Mountain regions could facilitate the development the immense windpower potential in these regions.
Emerging Storage Options
Other storage technologies are in earlier stages of development or commercial use or are not
available for utility-scale applications. These include batteries, compressed air, and thermal storage.9
Batteries. Batteries use reversible chemical reactions to store electricity, and are frequently used in
•stand-alone' (not grid connected) solar or windpower systems. These options are still being
investigated for utility-scale applications and questions remain as to their performance and costs in
the near term. The two leading contenders for utility-scale application are advanced lead-acid
batteries and zinc-chloride batteries, but zinc-bromide and sodium-sulfur have promise as well. The
chief advantage of batteries are modularity: battery installations can be scaled to utility needs and
expanded as needs increase. Currently, batteries supply storage for many small stand-alone PV and
windpower systems, and continued research and demonstration of battery technologies may make
battery storage more cost-effective for larger scale grid-connected applications.
Compressed Air Energy Storage (CAES). CAES systems use electric power to pressurize an
underground cavern, releasing the air through a turbine when electricity is needed. Like pumped
storage, CAES systems would primarily pump air during offpeak night hours, and would be most
suitable for wind energy generation. These plants can also be used to provide compressor power for
conventional gas turbines used in peaking operation, which reduces the energy needeo to drive the
turbine by about two-thirds (only one-third of the energy used in turbines provides net power, the
8 Smith, D.R. The Wind Farms of the Altamont Pass Area" Annual Energy Review. 1987.
9 A discussion of batteries and compressed air storage is found in New Electric Power Technologies:
Problems and Prospects for the 1990s, U.S. Office of Technology Assessment, 1985.
X-6
-------
TABLE X • 1
PUMPED STORAGE HYDROELECTRIC PLANTS OR ADDITIONS
Developed, Under Construction, or Projected
M of January 1988
(Kilowatts)
REGION
New England
Mid-Atlantic
South Atlantic
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
Total U.S.
Developed
1,453,000
2,902,887
3,994,094
1,978,800
600,802
1,530,000
299,050
510,000
148,500
3,360,150
314,000
17.091,283
Under
Construction
0
0
1,975.000
0
0
0
0
0
0
0
0
1,975,000
Other
Projected
75,000
1,727.000
2,250,000
1,530,000
2,376,800
0
1,660,000
3,998,200
1,950,000
735,750
820,000
17,122,750
Total
1,528,000
4,629,887
8,219,094
3,508,800
2,977,602
1,530,000
1,959,050
4,508,200
2,098,500
4,095,900
1,134,000
36,189,033
Source: Federal Energy Regulatory Commission, Hydroelectric Power Resources of the United
States - Developed and Undeveloped. January 1, 1988,
Note: Florida does not have any pumped storage capacity.
X-7
-------
other two-thirds drives the compressor). A 290 MW CAES that uses an underground salt dome for the
pressure chamber has operated in Huntorf, Germany since 1978; and a pilot plant (also using a salt
dome) is being built in Mclntosh, Alabama, for load leveling. Suitable geological features exist
throughout the U.S. for CAES development.
Thermal Storage. Instead of fossil fuel backup, solar thermal electric plants can employ thermal
storage to compensate for short cloudy periods or to shift power output to late afternoon or early
evening peak periods. The Solar One plant at Barstow California used a thermal oil/rock storage tank,
which provided several hours of storage under cloudy conditions. Other thermal storage options are
oil and molten salts. Molten salt offers the potential for longer storage periods, up to a few days,
further firming' this resource. Thermal storage is most suited for solar thermal applications, since the
thermal cycle is already part of the plant's operation.
Future Storage Options
Superconducting magnetic energy storage systems offer long-term promise for electrical
storage, but have been demonstrated only in small applications and are unlikely to provide economic
storage in the near term unless breakthroughs are make in high-temperature superconductive
materials. Hydrogen created by PV electrolysis of water represents a storage potential capable of
providing utility and transportation fuel. Hydrogen combustion does not produce CO2, and hydrogen
can be stored and transported through pipelines similar to natural gas pipelines (which can be
converted to hydrogen transport). A recent study by World Resources Institute examines the
prospects of PV derived hydrogen to provide transportation fuels, and suggests that if technology or
manufacturing breakthroughs occur and PV costs drop, a transition to renewable hydrogen fuels
could begin by the turn of the century.10
SENSITIVITY ANALYSIS OF AVOIDED COST
The renewable electric model (REM) was modified in order to make additional cost
comparisons of hybrid options for photovoltaic and windpower (the model already accounts for solar
thermal hybrid systems). The cost estimates should be viewed as illustrative, since the simple
assumptions employed do not take into account more complex technical and operational
characteristics of electric utility system operation. However, they do reveal some of the economic
tradeoffs encountered in using hybrid systems to firm intermittent renewable generation.
10 Joan M. Ogden and Robert H. Williams. Solar Hydrogen: Moving Beyond Fossil Fuels, World Resources
Institute, 1989.
X-8
-------
Hybrid Assumptions
The sensitivity analysis assumes that a natural gas combustion turbine (CT) is used to firm the
intermittent resource. The turbine costs $400 per kilowatt installed, operates at a heat rate of 13,500
Btu/kWh, and costs 1.0 0/kWh to operate and maintain. These assumptions are representative of CT
systems evaluated in the 1989 EPRI Technical Assessment Guide. The heat rate assumes that the CT
operates at 75% load on average; intermittent resources could effect CT operation in various ways,
but 75% load is reasonable. Regional natural gas fuel prices are already imbedded in the model, and
vary by season. The spring/fall prices were used as annual averages, since they tend to be between
summer and winter prices.
The CT is only operated to firm" the intermittent resource, and therefore operates at low
capacity factors typical of a peaking unit. (An alternative strategy could be to enhance capacity
utilization by supplying more generation than what is required to compensate for resource variability
during peak load periods.) No attempt was made to selectively alter seasonal/daily generation
patterns from PV, since PV generation occurs during the peak periods as defined in the model (except
for winter peaking regions). For PV, therefore, the contribution of the CT is assumed simply to
increase annual capacity factor. For windpower, two cases were examined. The first simply increases
capacity factor as in the PV case, without altering seasonal or daily generation profiles. Another case
shifts some of the annual generation to the summer daytime period in regions where utilities
experience peak demand during the summer and windpower is typically low during the summer
months. This 'shift' case illustrates the value of CT output to augment the more random seasonal and
daily patterns of windpower.
CT capital costs are attributed to the renewable technology, and operating and fuel costs are
apportioned to renewable generation, taking into account the assumed hours of operation. Two CT
operation scenarios were examined. In the conservative 'Full Backup" scenario, the CT is assumed to
be of the same scale as the renewable capacity, and operates at a 10% annual capacity factor. In the
"Partial Backup" scenario B, the CT is assumed to be built at 60% of the rated renewable technology
capacity, and only operates at an annual capacity factor of 5%. These CT operation scenarios were
applied to the EPA Base Case and the EPA Enhanced Market renewable cost assumptions. In all
cases, the 'capacity credit" for wind and PV generation was boosted to 100%. This implies that
utilities would value the generation from hybrid technologies as much as firm, dispatchable,
conventional capacity.
X-9
-------
Sensitivity Analysis Results
The analysis suggests that CT-based hybrid options would increase the competitiveness of
windpower in 2000 in several regions, and substantially increase the competitiveness of both
windpower and PV in 2010 in most regions. Tables X-2 through X-4 display the results of the hybrid
cost analysis of windpower in 2000 and 2010, and PV in 2010 (the PV hybrid results for 2000 indicated
that PV was still not broadly competitive).
Windpower. The conventional cost comparisons for windpower assumed a capacity credit equal to
1/3 the regional capacity factor in 2000 and 1/2 the regional capacity factor in 2010. Under these
assumptions, windpower generation in 2000 would be equal to avoided cost in California in the
Enhanced Market scenario, and would be within 0.5 c/kWh of avoided costs in New England
(Enhanced Market scenario) and California (Base Case).
The range of avoided costs in the windpower tables for the hybrid cost comparisons reflect
the impact of the shifting strategy. The lower figure is the avoided cost of the wind-CT hybrid
generation assuming no change in the seasonal generation pattern, while the higher figure gives the
avoided costs of windpower generation when the wind-CT hybrid generation is shifted to utility peak
seasons. The shift can increase the value of windpower-CT hybrid generation (as measured by
avoided fossil fuel and capacity costs) by as much as 2 e/kWh in some regions.
Despite higher generation costs attributed to building and operating the CT hybrid windplants,
the hybrid strategy would make windpower more competitive. If partial backup can give windpower
full capacity credit (as suggested in the U.S. Windpower study discussed above) then Table X-2
shows that windpower woulc stay competitive (within 0.5 e/kWh) under Base Case costs in New
England and California, and also become competitive in the West North Central and Mountain regions.
In Washington/Oregon, windpower-CT hybrids would become less expensive than fossil fuel
generation. Under the costs assumed in the Enhanced Market scenario, windpower-CT hybrids would
be within 0.5 c/kWh in New England, West North Central, and West South Central regions, while
windpower-CT hybrid generation costs would be equal to or lower than conventional costs in the
Mountain, California, and Washington/Oregon regions.
As Table X-3 shows, windpower-CT hybrids would be competitive in nearly every region under
a variety of assumptions. In the Partial Backup/Enhanced Market scenario assumptions, windpower is
extremely competitive in every region except for Florida and East South Central (where the wind
resource is so poor that the REM does not consider windpower feasible). Besides those two regions,
and in the South Atlantic region (where windpower hybrid generation is within 0.3 0/kWh of
X-10
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conventional costs, windpower-CT hybrid generation would be less expensive than conventional
generation.
Photovottaics. Under conventional cost comparisons, PV generation becomes less expensive than
fossil fuel generation in the Enhanced Market scenario in the West South Central and California
regions; and is within 0.1 0/kWh of fossil generation costs in Arizona/New Mexico. In other regions
shown on Table X-4, levelized PV costs in the Enhanced Market Scenario are between 1.0 c/kWh
(e.g., Mountain) and 4.3 c/kWh (e.g., Washington/Oregon) more expensive than fossil fuel generation.
CT-hybrid PV generation is more competitive than PV alone. In the Enhanced Market
scenario, PV-CT hybrid generation is within 0.5 c/kWh in Florida and the East South Central region
(Partial Backup case) and less expensive in the West South Central, Mountain, Arizona/New Mexico,
and California regions. Even if full backup were required, PV-CT hybrid generating costs in the
Enhanced Market Scenario remain below fossil fuel generating costs in the West South Central,
Arizona/New Mexico, and California regions, and would be only 0.1 C/kWh higher in the Mountain
region.
Conclusions
Most storage and backup technologies are best evaluated on a system perspective, where the
opportunity set for optimization is broader. This requires sophisticated modelling and control
strategies, but enlarging the focus from individual plant evaluation to a full range of supply and
demand-side options may enhance the economic prospects of intermittent renewable generation.
As stated before, these results are based on a simplified methodology, and must be regarded
as suggestive. Additional utility and technology-specific studies are needed to calculate the value of
hybrid options in a more definitive way. The emissions from CT generation (primarily NOX) should be
taken into account when evaluating the overall environmental impact of hybrid options; however, the
emissions expected from infrequent CT operation would be less than the emissions from using fossil
fuels to generate the electricity produced from the renewable hybrid system. Therefore, hybrid
options can enhance the value of intermittent renewable generation with less environmental impact
than pure fossil fuel-fired electric generation.
X-14
-------
EPILOGUE
The market for renewable electric generation has evolved dramatically since
the 1970s. Renewable resources have emerged as commercial alternatives to fossil
fuel-fired generation, and their environmental advantages are becoming more
recognized. Among these advantages, this report emphasizes the potential for
renewable electric technologies to reduce emissions of air pollutants and greenhouse
gases. In the 1990s, renewables face a market characterized by two related, but
different views. These two views are represented in the pictures that follow.
The first of these emphasizes the growing momentum of commercial
renewable development, where expansion is propelled by recent economic, regulatory,
and political trends. These include the Clean Air Act Amendments of 1990; regulatory
reform in electricity markets that influences utility investment; the 'Quiet Revolution1 of
public opinion and local activism; increased concern over the national security
implications of fossil fuel dependence; expanding international awareness of, and
markets for, renewable technology; and international concern over the implications of
increased greenhouse gas concentrations in the atmosphere. This confluence of
trends has helped position renewables for rapid growth.
The second view recognizes that renewables must compete aggressively with
fossil fuels in the domestic energy market, and that fossil fuels have historically held
the lead in such a competition. The rapid expansion of fossil fuel-fired electric
generation in the past was characterized by declining costs and more limited concern
over environmental impacts than exists today. The early market prospects for
renewables were limited by relatively high costs, lack of market access and utility
awareness, and a low value attached to the environmental advantages of renewable
E-1
-------
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HISTORICAL
•~*»L.V" , v, , «*,^-,-,,.«,^ _,„ •.
The Race Is Not Over...
E-3
-------
energy. Entering the 1990s, however, fossil fuels may encounter more resistance in
the market as all of the costs to society of fossil fuel use are recognized. At the same
time, the competitive stature of renewables has been enhanced by falling costs,
regulatory trends, increased public support, and growing awareness of the
environmental advantages of renewable energy sources. The extent to which these
factors will boost renewables' competitive position is still unclear.
These two views of renewable energy prospects - growing momentum and
intense competition - are not mutually exclusive. Renewable energy developers
regard the current momentum as cause for optimism, but not complacency; and
renewables will continue to face stiff challenges in competitive markets. Growing
recognition of the environmental benefits of renewable energy development,
supportive policies in the regulated electricity market, and continued commercial
success offer the prospect for a sustained expansion of renewable electric generation
in the 1990s and beyond. This report highlights the vast potential for development of
renewable electric generation and its ability to prevent air pollution. The report
demonstrates the potential for renewable electric generation to [help mitigate] the dual
problems of air pollution and fossil fuel dependence. However, this potential can only
be realized through the combined efforts of policymakers, researchers, utility planners,
and utility commmissions. Continued investment-by industry and government-is
crucial. -,
Cathy Zoi
Project Officer, Global Change Division
Office of Air and Radiation
U.S. Environmental Protection Agency
E-4
-------
APPENDIX A
RENEWABLE ELECTRIC TECHNOLOGY PENETRATION SCENARIOS
The Renewable Electric Model (REM) described in Chapter III estimates pollution prevention
and costs based on assumed renewable electric technology penetration scenarios. In order to
estimate pollution reduction potential and costs, the EPA constructed a Base Case and an Enhanced
Market scenario. Many of the technical and cost assumptions were taken from the recent analysis
conducted by the Department of Energy (DOE) and the Solar Energy Research Institute (SERI).1 For
some technologies, the DOE/SERI market projections formed the basis for EPA scenarios, while for
other technologies, EPA constructed scenarios based on other sources and data This appendix
describes how the scenarios were constructed for each technology considered in the report.
BIOMASS ELECTRIC SCENARIOS
EPA made separate technology penetration scenarios for the three biomass fuel sources:
solid combustion (primarily wood and wood waste), municipal solid waste, and landfill gas. The EPA
Base Case generally follows the DOE/SERI Business as Usual assumptions, except for MSW and
landfill methane, where the Base Case was derived from EPA analysis of potential fuel supply. The
EPA Enhanced Market scenario is based on analyses of individual biomass technologies and
respective fuel supplies. Because biomass technologies operate as reliably as fossil fuel systems
when adequate fuel is available, all technologies are given full capacity credit in the REM.
Wood. Wood Waste, and Agricultural Waste
Table A-1 shows the assumptions used in constructing the EPA scenarios. The EPA Base
Case for wood and wood waste essentially equals the DOE/SERI BAU scenario. Under this scenario,
electricity generation equals about 70 million mWh in 2000 and over 100 million mWh in 2010. Costs
and emissions for the Base case scenario are calculated based on the following mix of conversion
technologies: for 2000, 75% of the capacity built would be conventional boilers, with Whole Tree
Burner systems (WTB) accounting for the remaining 25% of capacity; wood-fired capacity built
1 The Potential of Renewable Energy, Interlaboratory White Paper prepared for the Office of Policy,
Planning, and Analysis, U.S. DOE (Golden, Colorado: Solar Energy Research Institute, March, 1990).
A-1
-------
TABLE A -1
MODEL ASSUMPTIONS FOR WOOD, WOOD WASTE, AND AGRICULTURAL WASTE
Assumption
SRWC FUEL SUPPLY
Available Acres;
Dry Cropland
Wet Cropland
Dry Pasture
Wet Pasture
Enrolled Acres:
Dry Cropland
Wet Cropland
Dry Pasture
Wet Pasture
Enrolled Acre Total
Average Annual Growth
Average Rotation
Wood Heat Content
FUEL COSTS
SRWC
Establishment Costs
Cropland
Pasture
Average Rental Rate
Treatment Costs
Harvesting and
Delivery Costs
Conventional Wood
Low Cost Regions
High Cost Regions
Unite
106 acres
10* acres
106 acres
106 acres
%
%
%
%
106 acres
dry
tons/acre/yr
years
mmBtu/dry ton
$/acre
$/acre
$/acre/yr
$/acre/year
$/dry ton
$/mmBtu
S/mmBtu
Value
117
107
16
24
25
25
25
25
63
4.7
8
17
250
280
53
26
16
2.50
3.50
Comments/Source
Land identified as eroding or
environmentally sensitive that
would benefit from tree
planting by Moulton (USFS)
and Richards (ERS/USDA).
In all regions except for
Arizona/New Mexico and
Mountain, where SRWC is
not thought to be viable on a
large scale.
Varies by region and land
type, estimated by L Wright
(ORNL). Tons of oven dried
wood equivalent.
Varies by region. Estimated
by L Wright
Equal to 8500 Btu/lb.
Estimated by L Wright.
Marginal rental rate
estimated by Moulton and
Richards. Varies by region
and land type.
Estimated by L Wright.
Estimated by L Wright At
low end of range of
estimates given since no
chipping necessary for WTB.
Representative regional
costs.
A-2
-------
Assumption
Wood, Wood Waste, and
Waste (continued)
Units
Agricultural
Value
Comments/Source
CONVERSION TECHNOLOGIES
Share of New Capacity
Base Case
Conventional Boiler
WTB
Enhanced Market
Conventional Boiler
WTB
Gas Turbine
Capital Costs
Conventional Boiler
WTB
Gas Turbine
Scenario Average
Base Case
Enhanced Market
O&M Costs
Conventional Boiler
WTB
Gas Turbine
Scenario Average
Base Case
Enhanced Market
Heat Rates
Conventional Boiler
WTB
Gas Turbine
Scenario Average
Base Case
Enhanced Market
Emissions Factors
CO2
CH4
NOX
S02
PM
%
$/kW
$/kW
$/kW
$/kW
$/kW
C/kWh
*/kWh
C/kWh
C/kWh
«/kWh
Btu/kWh
Btu/kWh
Btu/kWh
Btu/kWh
Btu/kWh
Ib/mmBtu
Ib/mmBtu
Ib/mmBtu
Ib/mmBtu
Ib/mmBtu
2000
75
25
75
25
2000
2,220
900
1,890
1,890
2000
0.6
0.3
0.5
0.5
2000
16,250
9,960
14,760
14,760
2000
0.0
0.0
0.25
0.04
0.05
2010
50
50
40
40
20
2010
2,220
900
1,220
1,560
1,490
2010
0.6
0.3
0.6
0.5
0.5
2000
16,250
9,960
10,500
13,210
12,690
2010
0.0
0.0
0.25
0.04
0.05
Based on assessment of
available and developing
technologies. Fluidized bed
combustion use would tower
emissions, but increase
costs.
EPRI TAG 1986
D. Ostlie (100 MW unit)
Larson et. al. (1989)
Mich. Elec. Option Study
0. Ostlie (100 MW unit)
Larson et. al. (1989)
Mich. Elec. Option Study
D. Ostlie (100 MW unit)
Larson et. al. (1989)
Mich. Elec. Option Study
EPA estimate
Mich. Elec. Option Study
A-3
-------
between 2000 and 2010 are assumed to be equally divided into conventional and WTB systems.
Because of its low heat rate (about 10,000 Btu/kWh, compared to 12,000-16,000 Btu/kWh for
conventional plants), and low fuel handling costs (especially with SRWC), WTB should quickly become
the 'state of the art* in wood-fired electricity generation, assuming that initial plants demonstrate these
advantages.
The EPA Enhanced Market scenario for wood and agricultural fuelstocks builds on the
DOE/SERI 'National Premiums' projection. Additional market enhancement in the form of promoting
extensive SRWC planting on marginal crop and pasture land to provide wood fuel for electricity
generation could result in a significant increase in generation over the DOE/SERI National Premiums
scenario.
SRWC can be chipped and used in conventional wood-fired boilers or utilized in whole tree
burners (WTB). Given the marked cost advantage of WTB over conventional boilers, especially when
using SRWC, the Enhanced Market scenario also assumes 25% of the new capacity built between
1990 and 2000 will be WTB, with conventional systems account for the remaining 75% of capacity.
Between 2000 and 2010, the Enhanced Market scenario assumes that WTB accounts for 40% of
capacity built, conventional systems account for 40%, and biomass combustion turbines account for
the remaining 20% of new capacity.
An estimate of the potential supply of wood fuel from SRWC on marginal cropland has been
made for the twelve EPA model regions using a SRWC supply model constructed by ICF. This model
calculates the total amount of wood available for harvest in a given year based on the amount of land
planted and the expected growth rates and rotation lengths for SRWC plantations. Additionally, fuel
prices have been determined based on marginal land rents, establishment and annual treatment
costs, and harvest and delivery costs.
Land considered in this analysis consists of marginal or environmentally sensitive crop and
pasture land. Most of this land is being eroded rapidly by either wind or water, and requires the
planting of a cover crop. When managed properly, short rotation trees can provide adequate
protection from erosion. Costs to establish SRWC plantations will vary depending on the amount of
site preparation that is required, with crop land requiring less preparation than pasture. Productivities
vary depending on the amount of water available: dry lands typically yield less than lands with
adequate moisture. Thus, land inputs for each region are classified as crop or pasture and as being
either wet or dry. The estimated amount of available land in each of these classifications is presented
in Table A-2. Productivity and cost inputs for each of these land classifications are provided in Table
A-3.
A-4
-------
TABLE A - 2
PROJECTED SRWC PLANTING ON MARGINAL LANDS BY REGION THROUGH 2010
(thousand acres)
REGION
New England
Mid Atlantic
South Atlantic
Florida
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
Total
Dry
Cropland
100
1,300
2,000
100
6,000
10,100
2,900
3,200
0
0
200
1,100
27,200
Wet
Cropland
100
1,200
1,300
100
7,200
8,400
2,800
4,100
0
0
100
800
26,100
Dry
Pasture
*
200
600
*
500
1,100
900
500
0
0
*
100
3.900
Wet
Pasture
100
400
500
200
700
1,400
900
1,200
0
0
70
170
5,600
Total
400
3,000
4,500
500
14,500
21,000
7,500
9,000
0
0
400
2,200
62,900
* Indicates land less than 50 thousand acres.
Note: Totals may not equal sum of columns due to independent rounding.
A-5
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Over 260 million acres of crop and pasture land are presently eroding or are environmentally
sensitive and would benefit from being enrolled in a program that takes them out of agricultural
production, such as the Conservation Reserve Program (CRP). This land base represents the total
acreage potentially available for SRWC planting on marginal lands, but not all of this land could be
planted with SRWC. The primary goal of programs like the CRP is to protect the land from further
damage. SRWC is one of a number of practices that can halt erosion and begin rebuilding the soils
(through root development and leaf litter). Therefore, EPA assumes that 25 percent of the available
land base will be planted with SRWC over the next twenty years in all regions except for the
Arizona/New Mexico and Mountain regions, where SRWC is not expected to be viable on a large
scale. A little over 60 million acres would be planted under these assumptions, averaging 3 million
acres planted per year over the next twenty years of enrollment Given that SRWC technology is still
developing, less land could be planted in earlier years; EPA assumes that in the first year about 1.5
million acres will be planted, an amount that would increasing steadily until the final year of analysis
when about 4.5 million acres will be planted. The rotation lengths used in this model average eight
years and annual growth is expected to average a little under 5 dry tons per acre per year.
The results of this analysis, including expected fuel supply, total costs, and resulting fuel
prices for the twelve model regions are presented in Table A-4. We expect that a total of roughly one
quad of wood fuel will be available for electricity generation in 2000 rising to 3.5 quads in 2010 at an
average price of roughly $2.70/mmBtu.2 Fuel prices for SRWC range from about $2.10/mmBtu in
Washington/Oregon to almost $3.50/mmBtu in the Northeast
Municipal Solid Waste
Both EPA scenarios for municipal solid waste-to-energy are based (WTE) on EPA projections
of MSW generation. Table A-5 shows the assumptions regarding mass-bum and refuse-derived fuel
plants in the EPA scenarios. In the Enhanced Market scenario, capital costs are reduced because of
increased commercial experience, which can lower construction costs and reduce the contingency
factor applied to capital cost estimates. These cost parameters are only illustrative, since the REM
analysis assumed that generation costs would equal avoided costs by construction. (This assumption
was made in order to account for common practice, and to avoid the need to forecast regional tipping
fees.) The heat rates and technology mix determine how much electricity could be generated for
assumed fuel supplies. Emission rates were taken from the Michigan Electric Option Study (1986).
2 Alternatively, liquid fuels can be produced with these SRWC fuelstocks. Assuming a conversion
rate of about 75 to 100 gallons of biocrude-derived gasoline per dry ton of wood, approximately 15 to
20 trillion gallons of gasoline could be produced in 2010. This is enough fuel to power 50 to 70
million automobiles travelling 10,000 miles per year at 35 mpg.
A-8
-------
TABLE A - 5
MUNICIPAL SOLID WASTE MODEL ASSUMPTIONS
Assumption
Capital Costs
Base Case
Mass Bum
RDF Plant
Enhanced Market
Mass Bum
RDF Plant
Ooeratina Cost
Base Case
Mass Bum
RDF Plant
Enhanced Market
Mass Bum
RDF Plant
Heat Rates
Mass Bum
RDF Plant
Capacity Factor
Emission Rates
SO2
NOX
CO
PM
Assumed
Technoloov Mix
(all years)
Unite
$/KW
$/KW
$/KW
$/KW
*/KWh
e/KWh
e/KWh
e/KWh
Btu/KWh
Btu/KWh
%
Ib./mmBtu
lb..mmBtu
Ib./mmBtu
lb..mmBtu
%
Value
2000
6,220
7,570
5,960
7,450
1.8
2.5
1.8
Z5
17,040
15,450
85
0.07
0.30
0.07
1.39
Mass
Burn
75
2010
6,220
7,570
5,710
7,340
1.8
2.5
1.8
2.5
17,040
15,450
85
0.07
0.30
0.07
1.39
RDF
Plant
25
Comments/Source
EPRI TAG $1990
EPRI TAG $1990
EPRI TAG - 25%, 50% contingency
EPRI TAG - 15%, 30% contingency
EPRI TAG $1990
EPRI TAG $1990
EPRI TAG $1990
EPRI TAG $1990
EPRI TAG $1990
EPRI TAG $1990
EPRI TAG
MEOS
MEOS
MEOS
MEOS
EPRI TAG projection
A-9
-------
In Characterization of Municipal Solid Waste prepared by Franklin Associates, the EPA
projects MSW generation to rise from the current 180 million tons per year to 216 million tons in 2000
and 250 million tons in 2010. The EPA Office of Solid Waste expects that 25% of the waste stream will
go to waste-to-energy (WTE) facilities in the year 2000. In the Base Case, EPA assumed that NIMBY
(not in my back yard) sentiments will keep the percent of MSW that goes to WTE facilities from
growing much beyond the current percentage through the year 2000 (although the total incinerated
will increase due to projected growth in total MSW generation). The Base Case share of MSW
generation accounted for by waste-to-energy in 2000 and 2010 is expected to equal 15 and 25
percent respectively.
For the Enhanced Market, the percent of MSW generation consumed by WTE facilities in each
region was scaled upwards such that (1) the national average equalled 25% in 2000 and 33% in 2010
and (2) regions with low percentages increased more rapidly than those with high waste-to-energy
percentages. Electric generation by WTE facilities is projected to equal roughly 33 million mWh in
2000 and grow to 50 million mWh in 2010.
Landfill and Digester Gas
EPA scenarios for landfill and digester gas are based on estimates of national totals since
regional data were not available at the time of this analysis. Since landfill gas currently accounts for
about 98 percent of electricity generation from landfill and digester gas, EPA projections are focused
on potential growth in this energy source. Current landfill methane generation was estimated using
the capacity data contained in The Power of the States, but the generation figures were calculated
using a 72% capacity factor, since the 90% capacity factor used in that study appeared unrealistically
high. Table A-6 shows the landfill conversion model assumptions, which were taken primarily from a
recent study of landfill generation economics.3
EPA regulations currently being considered for control of VOCs from large landfills would
mandate that gas collection devices be installed at all landfills meeting certain size criteria It is
estimated that the 850 largest landfills are responsible for about 60 percent of landfill methane
emissions in the U.S.. These landfills will likely be affected by this regulation, assumed to take affect
by the year 2000. Assuming that 65 percent of landfill gas from these landfills is captured,
approximately 0.1 quads of energy will be available for electricity generation. For comparison, it is
3 Bill Wolf and Greg Maxwell, 'Commercial Landfill Gas Recovery Operations - Technology and
Economics,' in Energy from Biomass and Wastes XIII, (Chicago: The Institute of Gas Technology),
1990.
A-10
-------
TABLE A - 6
LANDFILL METHANE CONVERSION MODEL ASSUMPTIONS
Assumption
Caoital Costs
Base Case
Reciprocating-Low
Reciprocating-High
Gas Turbine
Enhanced Market
Reciprocating-Low
Reciprocating-High
Gas Turbine
Ooeratina Cost
Base Case
Reciprocating-Low
Reciprocating-High
Gas Turbine
Enhanced Market
Reciprocating-Low
Reciprocating-High
Gas Turbine
Heat Rates
Reciprocating-Low
Reciprocating-High
Gas Turbine
Capacity Factors
Reciprocating-Low
Reciprocating-High
Gas Turbine
NOx Emission Rates
Reciprocating-Low
Reciprocating-High
Gas Turbine
CO Emission Rates
Reciprocating-Low
Reciprocating-High
Gas Turbine
Methane Emission Rate
Assumed Technoloov Mix
Reciprocating-Low
Reciprocating-High
Gas Turbine
Units
$/KW
$/KW
$/KW
$/KW
$/KW
$/KW
C/KWh
e/KWh
0/KWh
C/KWh
«/KWh
e/KWh
Btu/KWh
Btu/KWh
Btu/KWh
%
%
%
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
%
%
%
Value
2000
1,150
2,560
1,770
1,030
2,310
1,590
1.6
1.8
1.1
1.6
1.8
1.1
11,690
12,330
15.560
65
65
80
3.33
1.39
0.16
1.20
0.50
0.13
•42.3
25
25
50
2010
1,150
2,560
1,770
920
2,050
1,420
1.6
1.8
1.1
1.6
1.8
1.1
11,690
12,330
15,560
65
65
80
3.33
1.39
0.16
1.20
0.50
0.13
-42.3
25
25
50
Comments/Source
EBW - XIII, p. 1260 ($1990)
EBW - XIII, p. 1260 ($1900)
EBW -XIII, p. 1260 ($1990)
EBW x 0.9 (2000) x 0.8 (2010)
EBW x 0.9 (2000) x 0.8 (2010)
EBW x 0.9 (2000) x 0.8 (2010)
EBW - XIII, p. 1260 ($1990)
EBW -XIII, p. 1260 ($1900)
EBW - XIII, p. 1260 ($1990)
EBW -XIII, p. 1260 ($1990)
EBW -XIII, p. 1260 ($1900)
EBW - XIII, p. 1260 ($1990)
EBW -XIII, p. 1259 ($1990)
EBW - XIII, p. 1259 ($1900)
EBW -XIII, p. 1259 ($1990)
EBW -XIII, p. 1259 ($1990)
EBW -XIII, p. 1259 ($1900)
EBW -XIII. p. 1259 ($1990)
EBW -XIII, p. 1259 ($1990)
EBW -XIII, p. 1259 ($1900)
EBW -XIII, p. 1259 ($1990)
EBW -XIII, p. 1259 ($1990)
EBW -XIII, p. 1259 ($1900)
EBW - XIII, p. 1259 ($1990)
CH4 input = emission reduced
^ *
Proportional to capacity size
A-11
-------
estimated that if all landfill gas emitted annually in the U.S. were captured, approximately 0.25 quads
of energy would be available for use. As projected by DOE/SERI, increased research and
development should result increase the use of digester gas, especially from MSW digestion. This
growth should push the national total to 0.15 quads of primary energy equivalents in 2010. We use
this estimate for the EPA Enhanced Market scenario for 2000.
Incremental generation totals were allocated to regions according to the distribution of MSW
generation 10 years prior, due to the lag between landfilling and methane generation. For example,
the incremental electricity generation from this source between the years 2000 and 2010 (about 5
million mWh) was allocated to regions according to the distribution of year 2000 MSW generation.
The EPA Base case scenario was assumed to be identical to the DOE/SERI Business as Usual
Scenario. It should be noted, however, that the initial (1988) DOE/SERI estimate of 0.01 quads of
primary energy equivalent is substantially below the EPA 1990 generation estimate. The emission
reductions computed from incremental generation between 1990 and 2000, therefore, are quite a bit
higher in the DOE/SERI BAU Scenario than in the EPA Base case scenario, even though the same
amount of generation was assumed in 2000. This is due to the discrepancy in initial generation
estimates.
GEOTHERMAL SCENARIOS
Table A-7 shows the capital and operating cost assumptions used in the analysis, which are
based on DOE/SERI data Geothermal conversion systems all operate as baseload capacity and are
given full capacity credit in the REM. The EPA Base Case is identical to the DOE/SERI Business as
Usual scenario. EPA constructed the Enhanced Market scenario based on the historical growth of the
geothermal industry (primarily hydrothermal) over the last 12 years, and DOE's analysis of the impact
of particular policy options on geothermal technologies. The EPA Enhanced Market Scenario
assumes that policies are put into place to encourage geothermal development.
Hydrothermal resource development has continued in the U.S. during times of decreased
federal funding for geothermal programs, and decreased costs of fossil fuels. Assuming an
accelerated federal and state support of hydrothermal, the EPA Enhanced Market scenario is based
on an annual growth rate of 8 percent through the year 2000, primarily in the West. This would result
in an energy contribution of 0.56 quads in the year 2000 and 1.25 quads in 2010.
Based on DOE and other analyses, geopressured brines are likely to develop most
significantly under a 'national premiums' scenario, since RD&D is well underway and does not appear
A-12
-------
TABLE A - 7
GEOTHERMAL MODEL ASSUMPTIONS
Assumption
Caoital Cost
Basecase
Hydrothermal
Geopressurized
Hot Dry Rock
Enhanced Market
Hydrothermal
Geopressurized
Hot Dry Rock
Ooeratina Cost
Basecsse
Hydrothermal
Geopressurized
Hot Dry Rock
Enhanced Market
Hydrothermal
Geopressurized
Hot Dry Rock
Capacity Factor
Capacity Credit
Units
$/KW
S/KW
$/KW
$/KW
$/KW
$/KW
e/KWh
C/KWh
e/KWh
C/KWh
«/KWh
C/KWh
%
%
Value
2000
1700
2700
2500
1600
2600
2200
1.8
2.6
2.3
1.8
2.4
2.0
80
100
2010
1700
2200
2300
1500
2100
1800
1.7
2.4
2.1
1.5
2.1
1.6
80
100
Comments/Source
DOE/SERI BAU
DOE/SERI RD&D
DOE/SERI BAU
DOE/SERI RD&D
DOE/SERI
Firm capacity
A-13
-------
to be the limiting factor in development. Assuming aggressive policies in the Enhanced Market
scenario, geopressured brines contribute approximately .02 quads in the year 2000, and .08 quads in
2010. Expansion of hot dry rock resources hinges on technological advances in the field in the
coming years. The DOE/SERI report projects that HDR could provide 0.05 quads in 2000 and 0.23
quads by 2010 under and intensified R.D&D program. These projections are adopted in the
Enhanced Market scenario. Magma does not contribute to the Enhanced Market scenario.
HYDROELECTRIC SCENARIOS
The operation of hydroelectric plants depends on streamflow availability, storage, and (to the
extent that a plant can be operated in peaking or load following mode) energy value criteria Since
energy value is utility-specific, storage availability is site-specific, and streamflow availability varies from
year to year, any representation of hydroelectric operation in an aggregate model is an approximation.
Seasonal variability was estimated by analyzing state-level monthly hydroelectric output data
for the years 1983-1989, as well as historical streamflow data4 Generation by state was aggregated
into the 12 EPA regions and monthly figures were aggregated into seasonal totals, so that the portion
of yearly generation that occurs during each season could be calculated in each region. In order to
estimate a "representative" seasonal output, a simple, unweighted average of the yearly figures was
used.
The four seasonal generation fractions were split further into daily profiles. Different rules were
applied to peak plants and run-of-river plants, although few plants run purely in one mode or another
during the entire year. Peak plants, for example, will operate continuously during high flow periods in
order to capture potential spill as power output. Conversely, run-of-river plants will operate in peaking
mode (and sometimes not at all) during low-flow seasons when insufficient flow exists for continuous
operation.5
For run of river operation in the three highest flow seasons, the seasonal portions were
multiplied proportionally by the times represented in the daily load segments, i.e. by 13/24 for peak
operation, and 11/24 for off-peak operation. During the lowest flow season in each region, run-of-river
plants are assumed to run in a modified peak mode, where the peak operation is 18/24 times the
4 Streamflow data was taken from The Water Atlas (Port Washington, New York: Water Information
Center, 1975). Monthly generation was derived from issues of Electric Power Monthly, published by
the Energy Information Administration.
5 See EPRI Increased Efficiency of Hydroelectric Power, June, 1982, p. 3-3.
A-14
-------
seasonal portion, and the off-peak generation is 6/24 times the seasonal portion. Fall is the lowest
flow season in all regions except New England and East North Central, when it occurs in summer. In
the South Atlantic region, both summer and fall were assumed to operate in modified peak mode.
The seasonal profiles were split differently for peaking plant operation. In regions that had
one or two distinct low seasons, plants only operated during the peak hours during those seasons,
i.e. the entire seasonal allocation was placed in peak time, and off-peak times were zero. For other
seasons, modified peak operation (18/24 to peak, 6/24 to off-peak) was assumed, which reflects
continuous operation during the very highest portions of the peak season, with peak operation during
the remainder. Since storage capacity is usually less than inflow during the highest flow periods,
operators run as much through the turbine as possible and spill the rest. Regional stream flow data
was also consulted in order to select seasons that operate in modified peak mode. The seasons for
modified peak operation are as follows:
PEAKING PUNTS RUN-OF-RIVER
Modified Peak
Season
Summer
Fall
Summer/Fall
Fall
Summer
Fall
Fall
Fall
Fall
Fall
Fall
Fall
Other factors can affect daily generation patterns. For example, evaporative transfer in
summer can reduce afternoon flows, causing peak flows to occur in very early morning (e.g. 6:00 am).
Pondage options that store a few hours of water can help shift these peaks to afternoon. In regions
dominated by winter or spring snowmelt, generation peaks can occur between 2 and 6 PM as a result
of higher daytime temperatures that increase melting. These factors were not taken into account.
Regional capacity credit for hydroelectric generation reflects two considerations-the
coincidence of peak flows with peak electricity demand and the seasonal variability of available power.
The fraction of seasonal peak generation that occurs in the utility demand peak season represents the
first concern. Thus, if peak generation occurs in the summer in a summer peaking utility, the fraction
A-15
REGION
New England
Mid Atlantic
South Atlantic
Florida
E. N. Central
W. N. Central
E. S. Central
W. S. Central
Mountain
Ariz/N. Mexico
California
Wash./Oregon
Modified Peak
Season
Spring
Spring
Winter/Spring
Spring
Spring
Spring/Summer
Winter/Spring
Spring
Spring
Spring/Summer
Spring
Winter/Spring
-------
TABLE A - 8
HYDROELECTRIC MODEL ASSUMPTIONS
Assumption Units
Caoital Costs
Refurbishment/upgrade S/KW
Expand existing facility S/KW
Power non-power dams S/KW
Restore retired site S/Kw
Ooeration & Maintenance e/KWh
Caoacitv Credit
Storage Plants
New England %
Mid Atlantic %
South Atlantic %
Florida %
East North Central %
West North Central %
East South Central %
West South Central %
Mountain %
Arizona/New Mexico %
California %
Washington/Oregon %
Run of River Plants
New England %
Mid Atlantic %
South Atlantic %
Florida %
East North Central %
West North Central %
East South Central %
West South Central %
Mountain %
Arizona/New Mexico %
California %
Washington/Oregon %
Plant Factors
Storage Plants %
Run-of-River Plants %
Value
350
1400
1800
800
0.5
44
59
43
68
50
67
48
45
68
70
70
67
32
42
31
49
35
48
34
32
49
50
50
48
12-44
27-54
Comments/Source
Representative costs based
on industry surveys.
DOE/SERI
Calculated as the ratio of
hydroelectric output in peak
flow season over the
hydroelectric output during
peak electric demand
season in each region. The
ratio is scaled by 0.7 to
account for adverse flow
conditions (drought).
Calculated as the ratio of
hydroelectric output in peak
flow season over the
hydroelectric output during
peak electric demand
season in each region. The
ratio is scaled by 0.5 to
account for adverse flow
conditions (drought).
Depends on regional project
mix (based on FERC data).
A-16
-------
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is 1 (as in California and Arizona/New Mexico). At the other extreme, only 62 percent of the peak
seasonal output occurs during the summer utility demand peak in the South Atlantic region. This
variable is further scaled by the factor 0.7 for peaking plants and 0.5 for run-of-river plants to account
for adverse flow conditions.
Because the EPA Scenarios were based on FERC data that identified existing and potential
projects by type (except for retired facilities), incremental storage capacity assumed in the EPA
scenarios was assumed to operate in peaking mode, while additional run-of-river and diversion
capacity was assumed to operate in run-of-river mode (as were all restored retired facilities). Costs
were assigned to each project type, although it should be noted that the costs of hydropower
expansion options are very site specific. Table A-8 shows the project costs assumed in the analysis,
and the capacity credits calculated. In the Base Case, very limited expansion is assumed to occur at
existing hydropower sites. Table A-9 shows the hydroelectric expansion assumptions used in the
Base Case analysts, and Table A-10 shows the assumptions used in the Enhanced Market scenario.
PHOTOVOLTAIC SCENARIOS
Projections of future PV sales are extremely sensitive to the presumed timing of cost
reductions, especially when future costs attain certain thresholds that make them competitive in utility
power generation. Table A-11 shows the costs and regional capacity factors used to construct the
EPA technology penetration scenarios.
Generation in the Base Case is identical to the DOE/SERI Business as Usual scenario, which
was allocated to the 12 REM regions according to received insolation. (Because the REM has
regional capacity factors, the capacity from the EPA Base Case generation differs somewhat from the
capacity imputed from the DOE/SERI generation figures.)
The EPA Enhanced Market PV scenario assumes an intensified RD&D budget will bring down
the costs of materials and production, and that environmental impacts are incorporated into least cost
utility planning. The Enhanced Market scenario is based on the alternative PV growth scenario
described in the DOE/SERI report. PV is very responsive to intensified R&D, and prices drop
significantly by the year 2000. At a threshold price of between 60/kWh and 100/kWh, explosive
growth would be expected to occur in the industry. A number of new players will then enter the
market, further increasing competition and reducing costs of PV energy. The EPA Enhanced Market
scenario assumes that PV generation costs could be reduced to 8 C/kWh by 2000 and to 50/kWh by
2010 (in regions of good insolation where capacity factors approach 30%). This would require capital
costs to fall to roughly $2,100/KW by 2000 and $1,150 by 2010, compared with the DOE/SERI BAU
A-19
-------
TABLE A-11
PHOTOVOLTAIC MODEL ASSUMPTIONS
Assumption Units
Capital Cost
Basecase $/KW
Enhanced Market $/KW
Ooeratina Cost
Basecase e/KWh
Enhanced Market e/KWh
Caoacitv Factor
New England %
Mid Atlantic %
South Atlantic %
Florida %
East North Central %
West North Central %
East South Central %
West South Central %
Mountain %
Arizona/New Mexico %
California %
Washington/Oregon %
Capacity Credit %
Value
2000 2010
3750 2750
2750 1230
0.2 0.2
0.2 0.2
16
16
21
21
19
23
21
25
26
29
26
18
Equal to
capacity
factor
Comments/Source
DOE/SERI BAU
(in $1990)
DOE/SERI Alternative
Scenario
DOE/SERI BAU
DOE/SERI RD&D
Based on solar
insolation data and
operating records for
plants in specific
regions.
Typically coincident
with utility peaking
needs.
A-20
-------
assumptions of $3,500 in 2000 and $2,100 in 2010. In other words, PV cost reductions are
accelerated by at least a decade.
The capacity credit for PV systems is assumed to equal the capacity factor. This reflects the
fact that the expected generation from PV systems will not displace fully the need to build the
conventional capacity, but that the correlation between maximum PV output and utility peaking needs
would be sufficient to earn partial capacity credit.
SOLAR THERMAL ELECTRIC SCENARIOS
The EPA Base case and Enhanced Market scenarios are derived primarily from the DOE/SERI
scenarios. Tables A-12 and A-13 show the assumptions used in constructing the EPA scenarios.
The EPA Base case is identical to the DOE/SERI Business as Usual scenario. The DOE/SERI
analysis considers hybrid systems, along with stand-alone systems with and without storage (peaking
systems), but does not indicate which technologies would be chosen. The economics of storage and
fuel backup are probably more favorable from the utility perspective than intermittent peak power,
unless the solar resource is extremely dependable or located in an area where weather forecasting is
reliable. In constructing the EPA Base Case, it was assumed that all capacity built between now and
2000 would be operated in natural gas hybrid mode. The capacity built between 2000 and 2010 was
assumed to be stand-alone (non-hybrid) systems with storage. This assumption reflects the
DOE/SERI belief that storage systems will be improved to the point where they are more economical
than natural gas backup systems.
The Enhanced Market scenario assumes that additional R&D brings about the level of market
deployment indicated in the DOE/SERI Intensified RD&D scenario, and features the additional
development of hybrid natural gas solar thermal systems. These grow at an annual average rate of
4% between 2000 and 2010, in addition to the growth in stand alone systems assumed to be the
same as in the DOE/SERI RD&D scenario.
WINDPOWER SCENARIOS
EPA scenarios for windpower are based on a model of regional windpower and fossil fuel
generation costs. The model calculates the difference between conventional costs (from the REM)
and projected windpower costs, which vary as a function of regional capacity factors. Wind energy
scenarios are based on regional cost differences, resource potential, and projected demand growth.
A-21
-------
TABLE A • 12
SOLAR THERMAL (NON-HYBRID) MODEL ASSUMPTIONS
Assumption
Capital Cost
BaMCaSS1
Systems w/ storage
Peaking
Assumed 50/50 mix
Enhanced Market
Systems w/ storage
Peaking
Assumed 50/50 mix
Ooeratina Cost
Basecase
Enhanced Market
Assumed 50/50 mix
Capacity Factor
New England
Mid Atlantic
South Atlantic
Florida
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
Capacity Credit
Units
$/KW
$/KW
$/KW
$/KW
$/KW
$/KW
t/KWh
0/KWh
0/KWh
%
%
%
%
%
%
%
%
%
%
%
%
% of capacity
factor
2000
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
38
39
43
39
NA
100
Value
2010
2570
1930
2250
1500
1120
1300
2.1
Z1
2.1
NA
NA
NA
NA
NA
NA
NA
38
39
43
39
NA
100
Comments/Source
DOE/SERI BAU
DOE/SERI BAU
(in $1990)
DOE/SERI RD&D
DOE/SERI RD&D
On $1990)
DOE/SERI BAU
DOE/SERI RD&D
(in $1990)
(Direct solar resource
not sufficient for
economic energy
production in these
regions.)
Based on solar
insolation data and
projected storage
capability.
Typically coincident
with utility peaking
needs.
A-22
-------
TABLE A-13
SOLAR THERMAL HYBRID MODEL ASSUMPTIONS
Assumption
Caoital Cost
Basecase
iujcfcjm^ojw
Enhanced Market
Operating Cost
Basecase
Enhanced Market
Gas Price
Capacity Factor
New England
Mid Atlantic
South Atlantic
Florida
East North Central
West North Central
East South Central
West South Central
Mountain
Arizona/New Mexico
California
Washington/Oregon
Capacity Credit
Heat Rate
Emissions
(gas input basis)
C02
CO
CH4
NOX
SO2
PM
Units
$/KW
$/KW
t/KWh
*/KWh
$/mmBtu
%
%
%
%
%
%
%
%
%
%
%
%
%
Btu/KWh
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
Ib./mmBtu
IbVmmBtu
Ib./mmBtu
Value
2000 2010
2570 1640
2250 1500
2.1 2.1
2.1 2.1
3.2-3.8 5.3-6.3
NA
NA
NA
NA
NA
NA
NA
33
35
38
35
NA
100
10,500
23.3
0.01
0.00005
0.11
0.0
0.00005
Comments/Source
DOE/SERI BAU ($1990)
Luz analysis of 80MW
plant (2000); DOE/SERI
RD&D(2010) ($1990)
DOE/SERI BAU ($1990)
DOE/SERI RDD ($1990)
Depends on region and
season.
Direct solar resoruce
not sufficient for
economic energy
production.
Based on solar
insolation data and
25% natural gas use.
Gas use provides firm
capacity
Radian (gas boiler)
Radian (gas boiler)
Radian (gas boiler)
Radian (gas boiler)
Radian (gas boiler)
Radian (gas boiler)
Radian (gas boiler)
A-23
-------
A series of regional cost differentials was calculated as the difference between the levelized
cost of windpower and the avoided utility costs, which depend on the assumed seasonal and daily
pattern of wind generation in each region. Four ranges of cost differentials are used as thresholds to
categorize wind energy penetration. The ranges defined for the cost differential (D) are: Range (1): 0
greater than 1; Range (2): D is greater than 0 and less than or equal to 1; Range (3): D is greater
than -1 and less than or equal to 0; and Range (4): D is less than or equal to -1. Each region was
assigned a resource development factor for wind based on the value of the cost differential. These
are shown on Table A-14.
The potential wind resource data used in the analysis were calculated by Pacific Northwest
Laboratory (PNL), taking into account the exclusion of land owing to environmental or land-use
considerations.6 The data reflects wind electric potential for the 48 contiguous states based on
current turbine technology (30 meter hub height) sited in Class 5 or above wind resources. The
regional resource potential was multiplied by the resource development factors defined in each
scenario, which yields the windpower potential that could be developed. These resource development
percentages were then scaled by EIA regional electric demand growth figures.7 In the Base Case,
growth factors in 2000 are: 1% growth for New England, South Atlantic, East North Central, Mountain,
Arizona/New Mexico, California, and Washington/Oregon; 2% growth for Mid-Atlantic and West North
Central; and no growth for West South Central. Growth factors for 2010 are 1% growth for West
South Central and Mountain and 2% for the remaining regions, except for Florida and East South
Central, which do not have wind resources. The capacity growth factors for the Enhanced Market
scenario reflect greater than anticipated demand for electric services; the growth factor in 2000 is 2%
and in 2010 is 2.5% for all regions.
Capital and O&M costs in the Base Case are identical to the DOE/SERI BAU scenario, and the
Enhanced Market scenario uses DOE/SERI RD&D costs, based on turbines operating in 13 mph
average wind speed regimes. Table A-15 lists specific scenario cost and capacity factor assumptions.
Modest capacity credits were assumed in the EPA scenarios. The capacity credit in 2000 was set at
1/2 the regional capacity factor; capacity credit in 2010 was assumed to be 2/3 the regional capacity
factor. This reflects growing attention paid to developing wind resources which coincide with utility
peak demand periods.
6 Elliot, D.L, LL Wendell, and G.L Gower. 'U.S. Areal Wind Resource Estimates Considering
Environmental and Land-Use Exclusions' presented at the American Wind Energy Association (AWEA)
Windpower '90 Conference, September 28, 1990.
7 Energy Information Administration, Annual Energy Outlook for U.S. Electric Power 1990,
Projections through 2010, Reference Table B1: Electric Power Data and Projections.
A-24
-------
CET SCENARIOS
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TABLE A -16
WIND ENERGY MODEL ASSUMPTIONS
Assumption
CaoitalCost
Basecase
Enhanced Market
Ooeratina Cost
Basecase
Enhanced Market
Capacity Factor
New England
Mid Atlantic
South Atlantic
Florida
East North Central
West North Central
East South Central
West South Central
Mountain
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California
Washington/Oregon
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Units
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$/KW 1000
$/KW 965
e/KWh 1.2
t/KWh 0.9
% 24
% 24
% 24
% NA
% 21
% 33
% NA
% 28
% 33
% 28
% 36
% 32
% of capacity 50
factor
Value
2010
950
850
1.0
0.8
30
30
30
NA
30
35
NA
33
35
33
36
35
67
Comments/Sourc*
DOE/SERI BAU
DOE/SERI RD&D
DOE/SERI BAU
DOE/SERI RD&D
Based on projected wind
turbine efficiencies and
regional wind resources.
Based on improved siting
for utility peaking.
A-26
-------
APPENDIX B: 12 REGION MODEL RESULTS
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APPENDIX C
RENEWABLE ELECTRIC MODEL DESCRIPTION
The Renewable Electric Model (REM) used in the cost and emission analysis is a set of linear
equations and coefficient matrices that estimate the avoided costs the displaced emissions from
regional projections of renewable electric generation.
Geographical Regions
A fundamental premise of the analysis is that regional variation in renewable energy resource
bases and in utility systems is an important determinant of the avoided costs and emissions from fossil
fuel generation. Twelve geographical regions are used to depict variation in renewable resource bases
and electricity supply systems.
Renewable Electric Levelized Costs
The REM converts cost and performance data for renewable electric technologies into
levelized (cents/kilowatthour) costs. These technical data are reported in Appendix A. The levelized
cost methodology (1) annualizes capital cost ($/KW) with a capital charge rate of 0.10; (2) allocates
the annual capital cost across yearly generation using a capacity factor (which can vary by region);
and (3) adds to this levelized capital cost the operating and maintenance (O&M) and fuel costs on a
cent/kWh basis. This is a conventional real levelization costing approach.
Renewable Electric Generation Profiles
Renewable resources can vary by region, season, and time of day. Solar technologies, for
example, only provide power during the daylight hours, while hydroelectric resources are usually
available more during the spring runoff and fall rainy seasons. Biomass generation, on the other hand,
depends only on fuel supplies that typically are available year round when adequate storage exists.
Thus, each renewable electric technology has an annual operating pattern or "generation profile" that
describes the likely hours of power supply during the year.
c-i
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Regional generation profiles were constructed for each technology for three seasons (winter,
summer, and spring/fall) and for peak (daytime) and off-peak (nighttime) periods. For each
technology, and each region, there were six coefficients (three seasons times two daily periods) which
represented the fraction of annual generation likely to occur in each seasonal/daily load segment. For
baseload technologies, constant annual operation was assumed. The annual output of intermittent
technologies were assigned to load segments based on available average resource data, although
subjective assessments were unavoidable for some resource/region combinations. These coefficients
only distributed the annual generation across time segments; they sum to one by construction. Thus,
they are distinct from a capacity factor, which expresses the fraction of hours during the year that a
plant will operate; nor are they related to the peak load reliability factors (capacity credits) used in the
avoided capital cost calculations.
Regional Electric Utility Description
Electric utilities vary their generation mix depending on the level of electricity demand. In
periods of low demand, such as nighttime, electric utilities operate only their lowest cost generation
plants, which are usually coal, nuclear, and in some regions hydroelectric plants. As demand levels
increase, they bring on line their more expensive oil and gas generation units. Since greenhouse gas
emission rates are significantly different for these different types of generation units, emissions can
vary significantly due to seasonal and time of day variations in renewable electric output levels.
Avoided costs depend on those factors plus a reliability component that determines whether renewable
electric generation can displace capacity builds in the long run.
The utility side of the REM depicts the generation units most likely to be displaced by
increased renewable electric contribution. The renewable electric generation - distributed by region,
season, and time of day through the generation profiles — is mapped onto identically dimensioned
matrices of coefficients that give avoided utility costs and emissions. These coefficients are based on
the plants that would otherwise be dispatched to meet seasonal and daily loads in each region. The
model incorporates judgments concerning the marginal (highest cost) fossil fuel-fired plants in the
utility dispatch decision for each load segment, as these would be the most likely plants "backed
down" to accommodate additional renewable generation.
c-2
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The marginal utility resource coefficients were based on extensive modeling experience with
the Integrated Planning Model (IPM) developed by ICF Resources. This detailed utility simulation
model has been used to model most of the major utility systems in the country. Those simulation
results informed the construction of the marginal resource coefficients, which are interpreted as the
dispatch mix used to generate the most expensive 25 percent of the electricity generated in the peak
and off-peak periods during each season. This assumed mix of fossil fuel generation resources -
coal-, oil-, and gas-fired units - provides the basis for evaluating the avoided utility costs and
emissions.
Avoided Emissions
Avoided emissions from renewable generation are a function of the marginal utility resource
coefficients described above. The assumed blend of fossil fuel units yield a marginal emission
coefficient for each load segment, based on the emission characteristics.
Emission estimates for carbon dioxide, carbon monoxide, nitrogen oxides, and methane were
based on national average rates for all fossil fuel generation types. Sulfur dioxide emission rates for
oil- and coal-fired power plants were based on regional SO2 emission rates.
National average fossil fuel emission rates were based on an analysis by Radian Corporation:
c-3
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UNIT TYP1
EMISSION FACTORS FOR ELECTRIC GENERATION
(KG/MMBTU OUTPUT)
J?O2 CO CH4
NOX
Residual Fuel Boiler
Distillate Fuel Boiler
Natural Gas Boiler
Coal - PC Wall Fired
243.980
233.370
159.117
350.054
0.047
0.047
0.056
0.045
0.003
0.000
0.003
0.003
0.627
0.211
0.785
1.484
Source: Radian Corporation, Emissions and Cost
Estimates from Globally Significant
Anthropogenic Combustion Sources of NOX, N2O,
CH4, and CO2, December 28, 1987.
Regional SO2 emission factors for oil- and coal-fired powerplants were developed from
DOE/EIA data from 1988. Several renewable electric technologies - such as biomass and solar
thermal/natural gas hybrid systems — emit some atmospheric pollutants. These emissions were netted
out from avoided emission estimates for these technologies.
Avoided Costs
Electricity avoided cost estimates were calculated from three components:
• avoided cost of oil, natural gas, and coal purchases;
• variable operation and maintenance costs; and
• capital cost of new capacity.
The fuel and O&M costs avoided were based on generation displaced by the marginal resource
coefficients for each region, season, and period. Avoided capital costs were more complicated, and
are determined by new capacity costs and renewable generation reliability in peak demand seasons.
c-4
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Avoided Fuel and O&M Costs
The avoided costs for electric utility purchases of oil and coal were derived from the EIA's
price projections.1 The natural gas fuel avoided costs were based on EIA projections and were
adjusted to reflect seasonal variations.
The electric utility variable operation and maintenance cost estimates used for this analysis
were 2.2 mills per kwh delivered for oil and gas plants and 3.3 mills per kwh for coal plants. These
cost estimates were based on data used in the Integrated Planning Model.
Avoided Capital Costs
The avoided capital cost estimates represent the costs savings associated with reduced need for
electric utility capacity additions. Electric utilities must have sufficient generating capacity to meet
the peak electricity demand for their system. When peak demand increases, the electric utility will
incur costs associated with the construction of additional generating capacity to meet that increase in
consumption and maintain their target capacity reserve margin. A reduction in demand growth or an
increase in renewable generation will lead to a cost savings due to avoided fossil capacity expansion.
For this analysis, the projections of the North American Electric Reliability Council were
used to construct regional capacity addition mixes for the year 2000. Between 2000 and 2010, new
capacity additions in each region are assumed identical to the nationwide average EIA projections.
The Electric Power Research Institute Technical Assessment Guide (EPRI TAG) provided the capital
cost data for new fossil-fuel generating units. The assumptions about future capacity additions and
capital cost data were blended to create a marginal capital cost for each region in the year 2000 and
2010.
Instead of spreading these capital costs over the entire load curve (i.e. the generation profile),
the capital costs were allocated to one peak period or split among two periods depending on the
1 Department of Energy, Energy Information Administration, Regional
Projections of End-Use Energy Consumption and Prices Through 2000. April
1989. Annual Energy Outlook 1990. January 12, 1990.
C-5
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region. The following table lists the assumed peak season(s) for each of the twelve regions. These
peak season assumptions were made based on seasonal peak generation data reported by the North
American Electric Reliability Council.2 In general, most regions are summer peaking or summer and
winter peaking. Only Florida and Washington/Oregon are winter peaking regions. Florida is a
winter peaking region apparently due to the influx of tourists during winter months.
SEASONAL PEAK GENERATION ASSUMPTIONS
Region
New England
Mid-Atlantic
South Atlantic
Florida
East North Central
East South Central
West North Central
West South Central
North Mountains
Arizona/New Mexico
Washington/Oregon
California
Peak Seasons
Summer and Winter
Summer
Summer
Winter
Summer and Winter
Summer
Summer
Summer
Summer and Winter
Summer and Winter
Winter
Summer
The electricity capacity cost estimates were allocated to either a single season (winter oj
summer) region, or split among the two peaks in two season (winter and summer) peaking regions.
The number of hours in a peak season was calculated based on a 13 hour peak time of day period and
2 North American Electric Reliability Council, 1989 Electricity Supply
and Demand. October, 1989.
C-6
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three months to a season. Thus, the number of hours in a peak period for regions with a single peak
season was estimated to be 1,186.3
This capital cost allocation was necessary to account for reliability when estimating potential
capacity avoided by expanding intermittent renewable generation. Each renewable technology was
assigned a "capacity credit" factor valued between zero (no capital displacement) and one (peak
reliability equivalent to fossil units). Baseload renewables such as biomass electric were given a
capacity credit of one; biomass generation is "firm" capacity that can be counted on during daily and
seasonal peak demand periods. Other renewables received partial capacity credit, such as wind and
solar technologies. The combination of the generation profile coefficient and the capacity credit will
determine the capital cost displaced by an intermittent renewable generation technology in a given
region. This costing methodology can reflect "coincidence factors," or the correlation between an
intermittent renewable resource and a regional utility system peak demand. High coincidence factors
make renewables nearly as valuable as dispatchable fossil fuel units, while low coincidence factors
will limit the avoided capital cost from expanded renewable electric generation. Capacity credits for
intermittent technologies are given in Appendix A.
3 The number of peak hours for a region with a single peak season was
calculated as follows:
1,186 = 8,760 hours per year * (13 hours in daily peak / 24 hours per
day) * (3 months per season / 12 months per year).
C-7
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