Power Technologies Energy Data Book

April 2005 • NREL/TP-620-37930

Third Edition
National Renewable Energy Laboratory 

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Technical Report 

NREL/TP-620-37930 

April 2005 

Power Technologies Energy 

Data Book 

Third Edition 

Compiled by J. Aabakken 

Prepared under Task No(s). ASA4.6065 
NOTICE

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iii

Table of Contents 

1.0 Introduction..............................................................................................................................1 

2.0 Technology Profiles 

Biopower..............................................................................................................................3 

Geothermal.........................................................................................................................11 

Concentrating Solar Power ................................................................................................19 

Photovoltaics......................................................................................................................25 

Wind...................................................................................................................................37 

Hydrogen............................................................................................................................45 

Advanced Hydropower ......................................................................................................51 

Solar Buildings...................................................................................................................57 

Reciprocating Engines .......................................................................................................65 

Microturbines.....................................................................................................................69 

Fuel Cells ...........................................................................................................................73 

Batteries .............................................................................................................................81 

Advanced Energy Storage..................................................................................................87 

Superconducting Power Technology .................................................................................93 

Thermally Activated Technologies....................................................................................99 

3.0 Electricity Restructuring 

3.1 States with Competitive Electricity Markets .......................................................101 

3.2 States with System Benefit Charges (SBC).........................................................102 

3.3 States with Renewable Portfolio Standards (RPS) ..............................................105 

3.4 States with Net Metering Policies........................................................................110 

3.5 States with Environmental Disclosure Policies ...................................................115 

3.6 Green Power Markets ..........................................................................................116 

3.7 States with Competitive Green Power Offerings.................................................118 

3.8 States with Utility Green Pricing Programs.........................................................126 

3.9 Renewable Energy Certificates............................................................................139 

3.10 State Incentive Programs .....................................................................................143 

3.11 Federal Agency Purchases of Green Power.........................................................148 

4.0 Forecasts/Comparisons 

4.1 Projections of Renewable Electricity Net Capacity.............................................149 

4.2 Projections of Renewable Electricity Net Generation .........................................150 

4.3 Projections of Renewable Electricity Carbon Dioxide Emissions Savings.........151

5.0 Electricity Supply 

5.1 U.S. Primary and Delivered Energy Overview....................................................153 

5.2 Electricity Flow Diagram.....................................................................................155 

5.3 Electricity Overview ............................................................................................156 

5.4 Consumption of Fossil Fuels by Electric Generators ..........................................157 

5.5 Electric Power Sector Energy Consumption .......................................................158 

5.6 Fossil Fuel Generation by Age of Generating Units............................................160 
iv

5.7 Nuclear Generation by Age of Generating Units ................................................161 

5.8 Operational Renewable Energy Generating Capacity ........................................162 

5.9 Number of Utilities by Class of Ownership and Nonutilities..............................163 

5.10 Top 10 Investor-Owned Utilities .........................................................................164 

5.11 Top 10 Independent Power Producers Worldwide ..............................................166 

5.12 Utility Mergers and Acquisitions.........................................................................167 

5.13a North American Electric Reliability Council (NREC) Map for the 

United States ........................................................................................................168 

5.13b Census Regions Map............................................................................................169 

6.0 Electricity Capability 

6.1 Electric Net Summer Capability ..........................................................................171 

6.2 Electric-Only Plant Net Summer Capability........................................................172 

6.3 Combined-Heat-and-Power Plant Net Summer Capability .................................173 

6.4 Regional Noncoincident Peak Loads...................................................................174 

6.5 Electric Generator Cumulative Additions and Retirements.................................175 

6.6 Transmission and Distribution Circuit Miles.......................................................176 

7.0 Electricity Generation 

7.1 Electricity Net Generation ...................................................................................177 

7.2 Net Generation at Electric-Only Plants................................................................178 

7.3 Electricity Generation at Combined-Heat-and-Power Plants ..............................179 

7.4 Generation and Transmission/Distribution Losses ..............................................180 

7.5 Electricity Trade...................................................................................................181 

8.0 Electricity Demand 

8.1 Electricity Sales ...................................................................................................183 

8.2 Demand-Side Management..................................................................................184 

8.3 Electricity Sales, Revenue, and Consumption by Census Division and 

State, 2003............................................................................................................185 

9.0 Prices 

9.1 Price of Fuels Delivered to Electric Generators ..................................................187 

9.2 Electricity Retail Sales.........................................................................................188 

9.3 Prices of Electricity Sold ....................................................................................189 

9.4 Revenue from Electric Utility Retail Sales by Sector..........................................190 

9.5 Revenue from Sales to Ultimate Consumers by Sector, Census Division, 

and State, 2003.....................................................................................................191 

9.6 Production, Operation, and Maintenance Expenses for Major U.S. 

Investor-Owned and Publicly Owned Utilities....................................................193

9.6a Operation and Maintenance Expenses for Major U.S. Investor-Owned 

Electric Utilities ...................................................................................................194 

9.6b Operation and Maintenance Expenses for Major U.S. Publicly Owned Generator 

and Nongenerator Electric Utilities .....................................................................195 

9.7 Environmental Compliance Equipment Costs.....................................................196 
v

10.0 Economic Indicators 

10.1 Consumer Price Estimates for Energy Purchases ................................................197 

10.2 Economy-Wide Indicators ...................................................................................198 

10.3 Composite Statements of Income for Major U.S. Publicly Owned Generator 

and Investor-Owned Electric Utilities, 2003 .......................................................199 

11.0 Environmental Indicators 

11.1 Emissions from Electricity Generators, 2003 ......................................................201 

11.2 Installed Nameplate Capacity of Utility Steam-Electric Generators with 

Environmental Equipment ...................................................................................203 

11.3 EPA-Forecasted Nitrogen Oxide, Sulfur Dioxide, and Mercury Emissions 

from Electric Generators......................................................................................204 

11.4 Market Price Indices for Emissions Trading in the South Coast Air-Quality 

Management District............................................................................................205 

11.5 Origin of 2003 Allowable SO2 Emissions Levels................................................206 

12.0 Conversion Factors 

12.1 Renewable Energy Impacts Calculation ..............................................................207 

12.2 Number of Home Electricity Needs Met Calculation..........................................208 

12.3 Coal Displacement Calculation............................................................................209 

12.4 National SO2 and Heat Input Data.......................................................................210 

12.5 SO2, NOx, CO2 Emission Factors for Coal-Fired and Non-Coal Fired Title IV 

Affected Units......................................................................................................211 

12.6a Sulfur Dioxide, Nitrogen Oxide, and Carbon Dioxide Emission Factors, 

2003 – Electricity Generators ..............................................................................212 

12.6b Sulfur Dioxide, Nitrogen Oxide, and Carbon Dioxide Emission Factors, 

2003 – Combined Heat and Power Producers .....................................................213 

12.7 Global Warming Potentials (GWP) .....................................................................215 

12.8 Approximate Heat Content of Selected Fuels for Electric Power Generation.....216 

12.9 Approximate Heat Rates for Electricity...............................................................217 

12.10 Heating Degree Days by Month ..........................................................................218 

12.11 Cooling Degree Days by Month ..........................................................................219 
1.1 - Introduction 

About the Power Technologies Energy Data Book (PTEDB), Third Edition 

In 2002, the Energy Analysis Office of the National Renewable Energy Laboratory 

(NREL) developed the first version of the Power Technologies Energy Data Book for the 

Office of Power Technologies of the U.S. Department of Energy (DOE). 

The main purpose of the data book is to compile – in one central document – a 

comprehensive set of data about power technologies from diverse sources. The need for 

policymakers and analysts to be well informed about power technologies suggests the 

need for a publication that includes a diverse, yet focused, set of data about power 

technologies. 

This edition updates the same type of information that is in the previous edition. Most of 

the data in this publication is taken directly from the source materials, although it may be 

reformatted for presentation. Neither NREL nor DOE endorses the validity of these data. 

This Third Edition of the Power Technologies Energy Data Book, and previous editions, 

are available on the Internet at http://www.nrel.gov/analysis/power_databook/, where the 

PTEDB may be downloaded as PDF files. Selected data also is available as Excel 

spreadsheets. 

The Web site also features energy-conversion calculators and features links to the 

Transportation Energy Data Book and Buildings Energy Data Book. Readers are 

encouraged to suggest improvements to the PTEDB through the feedback form on the 

Web site. 

1
2
Biopower

Technology Description 

Biopower, also called biomass power, is the generation of electric power from biomass resources – 

now usually urban waste wood, crop and forest residues; and, in the future, crops grown specifically for 

energy production. Biopower reduces most emissions (including emissions of greenhouse gases-GHGs) 

compared with fossil fuel-based electricity. Because biomass absorbs CO2 as it grows, the entire 

biopower cycle of growing, converting to electricity, and regrowing biomass can result in very low CO2

emissions. Through the use of residues, biopower systems can even represent a net sink for GHG 

emissions by avoiding methane emissions that would result from landfilling of the unused biomass. 

Representative Technologies for Conversion of Feedstock to Fuel for Power and Heat 

• Homogenization is a process by which feedstock is made physically uniform for further processing or 

for combustion (includes chopping, grinding, baling, cubing, and pelletizing). 

• Gasification (via pyrolysis, partial oxidation, or steam reforming) converts biomass to a fuel gas that 

can be substituted for natural gas in combustion turbines or reformed into H2 for fuel cell applications. 

• Anaerobic digestion produces biogas that can be used in standard or combined heat and power (CHP) 

applications. Agricultural digester systems use animal or agricultural waste. Landfill gas also is 

produced anaerobically. 

 • Biofuels production for power and heat provides liquid-based fuels such as methanol, ethanol, 

hydrogen, or biodiesel. 

Representative Technologies for Conversion of Fuel to Power and Heat 

• Direct combustion systems burn biomass fuel in a boiler to produce steam that is expanded in a 

Rankine Cycle prime mover to produce power. 

• Cofiring substitutes biomass for coal or other fossil fuels in existing coal-fired boilers. 

• Biomass or biomass-derived fuels (e.g. syngas, ethanol, biodiesel) also can be burned in combustion 

turbines (Brayton cycle) or engines (Otto or Diesel cycle) to produce power. 

• When further processed, biomass-derived fuels can be used by fuels cells to produce electricity 

System Concepts 

• CHP applications involve recovery of heat for steam and/or hot water for district energy, industrial 

processes, and other applications. 

• Nearly all current biopower generation is based on 

direct combustion in small, biomass-only plants with 

relatively low electric efficiency (20%), although total 

system efficiencies for CHP can approach 90%. Most 

biomass direct-combustion generation facilities utilize 

the basic Rankine cycle for electric-power generation, 

which is made up of the steam generator (boiler), 

turbine, condenser, and pump. 

• For the near term, cofiring is the most cost-effective of 

the power-only technologies. Large coal steam plants 

have electric efficiencies near 33%. The highest levels 

of coal cofiring (15% on a heat-input basis) require 

separate feed preparation and injection systems. 

• Biomass gasification combined cycle plants promise 

comparable or higher electric efficiencies (> 40%) using 

only biomass, because they involve gas turbines (Brayton cycle), which are more efficient than 

Rankine cycles. Other technologies being developed include integrated gasification/fuel cell and 

biorefinery concepts. 

3
Technology Applications 

• The existing biopower sector – nearly 1,000 plants – is mainly comprised of direct-combustion plants, 

with an additional small amount of cofiring (six operating plants). Plant size averages 20 MWe, and the 

biomass-to-electricity conversion efficiency is about 20%. Grid-connected electrical capacity has 

increased from less than 200 MWe in 1978 to more than 9700 MWe in 2001. More than 75% of this 

power is generated in the forest products industry’s CHP applications for process heat. Wood-fired 

systems account for close to 95% of this capacity. In addition, about 3,300 MWe of municipal solid 

waste and landfill gas generating capacity exists. Recent studies estimate that on a life-cycle basis, 

existing biopower plants represent an annual net carbon sink of 4 MMTCe. Prices generally range from 

8¢/kWh to 12¢/kWh. 

Current Status 

• CHP applications using a waste fuel are generally the most cost-effective biopower option. Growth is 

limited by availability of waste fuel and heat demand. 

• Biomass cofiring with coal ($50 - 250/kW of biomass capacity) is the most near-term option for 

large-scale use of biomass for power-only electricity generation. Cofiring also reduces sulfur dioxide 

and nitrogen oxide emissions. In addition, when cofiring crop and forest-product residues, GHG 

emissions are reduced by a greater percentage (e.g. 23% GHG emissions reduction with 15% cofiring). 

• Biomass gasification for large-scale (20 - 100MWe) power production is being commercialized. It 

will be an important technology for cogeneration in the forest-products industries (which project a need 

for biomass and black liquor CHP technologies with a higher electric-thermal ratio), as well as for new 

baseload capacity. Gasification also is important as a potential platform for a biorefinery. 

• Small biopower and biodiesel systems have been used for many years in the developing world for 

electricity generation. However, these systems have not always been reliable and clean. DOE is 

developing systems for village-power applications and for developed-world distributed generation that 

are efficient, reliable, and clean. These systems range in size from 3kW to 5MW and completed field 

verification by 2003. 

• Approximately 15 million to 21 million gallons of biodiesel are produced annually in the United 

States. 

• Utility and industrial biopower generation totaled more than 60 billion kWh in 2001, representing 

about 75% of non-hydroelectric renewable generation. About two-thirds of this energy is derived from 

wood and wood wastes, while one-third of the biopower is from municipal solid waste and landfill gas. 

Industry consumes more than 2.1 quadrillion Btu of primary biomass energy. 

• Current companies include:

Cargill-Dow Foster Wheeler 

Energy Products of Idaho Genecor International 

 Future Energy Resources, Inc. (FERCO) PRM Energy Systems

Technology History 

• In the latter part of the 19th century, wood was the primary fuel for residential, commercial, and 

transportation uses. By the 1950s, other fuels had supplanted wood. In 1973, wood use had dropped to 

50 million tons per year. 

• At that point, the forest products and pulp and paper industries began to use wood with coal in new 

plants and switched to wood-fired steam power generation. 

• The Public Utility Regulatory Policies Act (PURPA) of 1978 stimulated the development of 

nonutility cogeneration and small-scale plants, leading to 70% self-sufficiency in the wood processing 

and pulp-and-paper sectors. 

• As incentives were withdrawn in the late 1980s, annual installations declined from just more than 600 

MW in 1989, to 300-350MW in 1990. 

• There are now nearly 1,000 wood-fired plants in the United States, with about two-thirds of those 

providing power (and heat) for on-site uses only. 

4
Technology Future

The levelized cost of electricity (in constant 1997$/kWh) for biomass direct-fired and gasification 

configurations are projected to be: 

 2000 2010 2020

Direct-fired 7.5 7.0 5.8 

Gasification 6.7 6.1 5.4 

 Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997. 

• R&D directions include: 

 Gasification – This technology requires extensive field verification in order to be adopted by the 

relatively conservative utility and forest-products industries, especially to demonstrate integrated 

operation of biomass gasifier with advanced-power generation (turbines and/or fuel cells). Integration 

of gasification into a biorefinery platform is a key new research area. 

Small Modular Systems – Small-scale systems for distributed or minigrid (for premium or village 

power) applications will be increasingly in demand. 

Cofiring – The DOE biopower program is moving away from research on cofiring, as this 

technology has reached a mature status. However, continued industry research and field verifications 

are needed to address specific technical and nontechnical barriers to cofiring. Future technology 

development will benefit from finding ways to better prepare, inject, and control biomass combustion 

in a coal-fired boiler. Improved methods for combining coal and biomass fuels will maximize 

efficiency and minimize emissions. Systems are expected to include biomass cofiring up to 5% of 

natural gas combined-cycle capacity. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

5
Biomass 

Market Data 

Cumulative Generating Capability, by Type (MW) 

 Source: Energy Information Administration (EIA), EIA, Annual Energy Review 2

(Washington, D.C., September 2004), Tables 8.11a and 8.11c, and world data Development Program, World Energy Assessment, 2000, Table 7.25. 

1980 1985 1990 1995 1996 1997 1998 1999 2

U.S. Electric Power Sector 

 Municipal Solid Waste1 N/A 151 1,852 2,733 2,600 2,528 2,636 2,614 2

 Wood and Other Biomass2 78 200 964 1,451 1,425 1,452 1,438 1,484 1

U.S. Cogenerators3 Municipal Solid Waste1 659 786 998 1,062 1,058 1,046 1

 Wood and Other Biomass2 4,585 5,298 5,382 5,472 5,364 5,311 4

U.S. Total  Municipal Solid Waste1 NA 151 2,511 3,519 3,598 3,590 3,694 3,660 3

 Wood and Other Biomass2 78 200 5,549 6,750 6,808 6,924 6,802 6,795 6

 Biomass Total 78 351 8,061 10,269 10,405 10,515 10,495 10,454 10

Rest of World Total4 29,505World Total 40,000

1 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other 

biomass. 

2 Wood, black liquor, and other wood waste. 3 Data include electric power sector and end-use sector (industrial and commercial) generators. 4 Number derived from subtracting U.S. total 

from the world total. Figures may not add due to rounding. 

6
U.S. Annual Installed 

Generating Capability, by Type (MW) 

 Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 

2003. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Agricultural Waste2 22.6 20.1 0 4.0 0 21.6 0 0 0 0 

Biogas3 0.1 58.6 51.3 17.5 74.8 92.7 87.3 107.6 43.8 66.8 

Municipal Solid Waste4 50.0 117.2 260.3 94.5 0 0 0 22.0 0 0 

Wood Residues5 260.4 254.8 299.4 66.5 91.6 40.0 90.3 13.0 0 11.3 

Total 333.0 450.7 611.0 182.5 166.4 154.3 177.6 142.6 43.8 78.1 

U.S. Cumulative Generating Capability, by Type6 (MW) 

 Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 

2003. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Agricultural Waste2 40 92 165 351 351 373 373 373 373 373 

Biogas3 18 117 361 526 601 694 781 889 933 999 Municipal Solid Waste4 263 697 2,172 2,948 2,948 2,948 2,948 2,970 2,970 2,970 

Wood Residues5 3,576 4,935 6,305 7,212 7,303 7,343 7,434 7,447 7,447 7,458 

Total 3,897 5,840 9,003 11,037 11,203 11,358 11,535 11,678 11,722 11,800 Note: The data in this table does not match data in the previous table due to different coverage ratios in EIA and REPIS database

1 2003 data not complete as REPiS database is updated through 2002. 2 Agricultural residues, cannery wastes, nut hulls, fruit pits, nut shells 3 Biogas, alcohol (includes butahol, ethanol, and methanol), bagasse, hydrogen, landfill gas, livestock manure, wood gas (from w4 Municipal solid waste (includes industrial and medical), hazardous waste, scrap tires, wastewater sludge, refused-derived fuel 5 Timber and logging residues (includes tree bark, wood chips, saw dust, pulping liquor, peat, tree pitch, wood or wood waste) 6 There are an additional 65.45 MW of Ag Waste, 5.445 MW of Bio Gas, and 483.31 MW of Wood Residues that are not account

have no specific online date. 

7
Generation from 

Cumulative Capacity, by Type (Million kWh) 

 Source: EIA, Annual Energy Review 2003, Tables 8.2a and 8.2c, and world data from United 

Development Program, World Energy Assessment, 2000, Table 7.25. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. Electric Power Sector 

 Municipal Solid Waste1 158 640 10,245 16,326 16,078 16,397 16,963 17,112 17,592 17,221 

 Wood and Other Biomass2 275 743 5,327 5,885 6,493 6,468 6,644 7,254 7,301 6,571 

U.S. Cogenerators3 Municipal Solid Waste1 2,904 4,079 4,834 5,312 5,485 5,460 5,540 4,543 

 Wood and Other Biomass2 26,939 30,636 30,307 30,480 29,694 29,787 30,294 28,629 

U.S. Total  Municipal Solid Waste1 158 640 13,149 20,405 20,911 21,709 22,448 22,572 23,131 21,765 

 Wood and Other Biomass2 275 743 32,266 36,521 36,800 36,948 36,338 37,041 37,595 35,200 

 Biomass Total 433 1,383 45,415 56,926 57,712 58,658 58,786 59,613 60,726 56,964 

Rest of World Total4 101,214 

World Total 160,000 1 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. 2 Wood, black liquor, and other wood waste. 3 Data include electric power sector and end-use sector (industrial and commercial) generators. 4 Number derived from subtracting U.S. total from the world total. Figures may not add due to rounding. 

U.S. Annual Energy Consumption for Electricity Generation (Trillion Btu) 

 Source: EIA, Annual Energy Review 2003, Tables 8.4b and 8.4c 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Electric-Power Sector 4.5 14.4 285.9 388.0 397.3 408.3 412.0 415.5 420.7 430.

Commercial Sector1 16.7 22.3 32.1 34.3 32.7 33.5 26.5 22.

Industrial Sector1 351.0 385.3 407.1 380.7 362.0 373.0 378.8 379.

Total Biomass 4.5 14.4 653.5 795.6 836.5 823.3 806.8 822.0 825.9 832.

Data include wood (wood, black liquor, and other wood waste) and waste (municipal solid waste, landfill gas, sludge waste, tiagricultural byproducts, and other biomass). 1 Data includes combined-heat-and-power (CHP) and electricity-only plants. 

8
Technology Performance Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997 (

currently being updated by DOE and the values most likely will change). 

Efficiency 1980 1990 19951 2000 2005 2010 

 Capacity Factor (%) Direct-fired 80.0 80.0 80.0 80.0 

Cofired 85.0 85.0 85.0 85.0 Gasification 80.0 80.0 80.0 80.0 

 Efficiency (%) Direct-fired 23.0 27.7 27.7 27.7 

Cofired 32.7 32.5 32.5 32.5 Gasification 36.0 36.0 37.0 37.0 

 Net Heat Rate (kJ/kWh) Direct-fired 15,280 13,000 13,000 13,000 

Cofired 11,015 11,066 11,066 11,066 

Gasification 10,000 10,000 9,730 9,730 

Cost 1980 1990 19951 2000 2005 2010  Total Capital Cost ($/kW) Direct-fired 1,965 1,745 1,510 1,346 

Cofired3 272 256 241 230 Gasification 2,102 1,892 1,650 1,464 

 Feed Cost ($/GJ) Direct-fired 2.50 2.50 2.50 2.50 

Cofired3 -0.73 -0.73 -0.73 -0.73 Gasification 2.50 2.50 2.50 2.50 

 Fixed Operating Cost ($/kW-yr) Direct-fired 73.0 60.0 60.0 60.0 

Cofired3 10.4 10.1 9.8 9.6 Gasification 68.7 43.4 43.4 43.4 

1980 1990 19951 2000 2005 2010 

 Variable Operating Costs ($/kWh) Direct-fired 0.009 0.007 0.007 0.007 

Cofired3 -0.002 -0.002 -0.002 -0.002 Gasification 0.004 0.004 0.004 0.004 

 Total Operating Costs ($/kWh) Direct-fired 0.055 0.047 0.047 0.047 

 Cofired3 -0.008 -0.008 -0.008 -0.009  Gasification 0.040 0.036 0.036 0.036 Levelized Cost of Energy ($/kWh) Direct-fired 0.087 0.075 0.070  Cofired3 N/A N/A N/A N/A 

Gasification 0.073 0.067 0.061 

1 Data is for 1997, the base year of the Renewable Energy Technology Characterizations analysis. 2 Number derived by interpolation. 3 Note cofired cost characteristics represent only the biomass portion of costs for capital and incremental costs above convent

Operations & Maintenance (O&M), and assume $9.14/dry tonne biomass and $39.09/tonne coal, a heat input from biomass a

that variable O&M includes an SO2 credit valued at $110/tonne SO2. No cofiring COE is reported in the RETC. 

9
10
Geothermal Energy

Technology Description 

Geothermal energy is thermal energy from within the Earth. Hot water and steam are used to produce 

electricity or applied directly for space heating and industrial processes. There is potential to use 

geothermal energy to recover minerals and metals present in the geothermal brine. 

System Concepts

• Geophysical, geochemical, and 

geological exploration locate permeable hot 

reservoirs to drill. 

• Wells are drilled into the reservoirs. 

• Well fields and distribution systems 

allow the hot geothermal fluids to move to 

the point of use, and are injected back to the 

earth. 

• Steam turbines using natural steam or 

hot water flashed to steam, and binary 

turbines produce mechanical power that is 

converted to electricity. 

• Direct applications utilize the thermal 

energy directly, for heating, without conversion to another form of energy. 

Representative Technologies 

• Dry-steam plants, which use geothermal steam to spin turbines. 

• Flash-steam plants, which pump deep, high-pressure hot water into lower-pressure tanks and use 

the resulting flashed steam to drive turbines. 

• Binary-cycle plants, which use moderately hot geothermal water to heat a secondary fluid with a 

much lower boiling point than water. This causes the secondary fluid to flash to vapor, which then 

drives the turbines. 

• Exploration technologies for the identification of fractures and geothermal reservoirs; drilling to 

access the resource; geoscience and reservoir testing and modeling to optimize production and predict 

useful reservoir lifetime. 

Technology Applications 

• Mile-or-more-deep wells can be drilled into underground reservoirs to tap steam and very hot water 

that drive turbines and electricity generators. Because of economies of scale, geothermal power plants 

supply power directly to the grid, typically operating as baseload plants. 

• Another use is direct applications to use the heat from geothermal fluids without conversion to 

electricity. In the United States, most geothermal reservoirs are located in the western states, Alaska, 

and Hawaii; but some eastern states have geothermal resources that are used for direct applications. Hot 

water near the Earth's surface can be piped directly into facilities and used to heat buildings, grow 

plants in greenhouses, dehydrate onions and garlic, heat water for fish farming, and pasteurize milk. 

Some cities pipe the hot water under roads and sidewalks to melt snow. District heating systems use 

networks of piped hot water to heat many buildings in a community. 

• The recovery of minerals and metals from geothermal brine can add value to geothermal-power 

projects. 

11
Current Status 

• Hydrothermal reservoirs provide the heat for about 2,400 MW of operating generating capacity in 

the United States at 18 resource sites. Another 700 MW of capacity at The Geysers was shut down. 

• Three types of power plants are operating today: dry steam, flash steam, and binary. 

• Worldwide installed capacity stands at about 8,000 MW. 

• The United States has a resource base capable of supplying heat for 40 GW of electrical capacity at 

costs competitive with conventional systems. With improved technology, this resource base could 

expand to 100 GW of electricity at 3 to 5¢/kWh. 

• Hydrothermal reservoirs are being used to produce electricity with an online availability of 97%; 

advanced energy conversion technologies are being implemented to improve plant thermal efficiency. 

• Direct applications capacity is about 600 MWt in the United States. 

• Direct-use applications are successful, but require colocation of a quality heat source and need. 

• More than 20 states use the direct use of geothermal energy, including Georgia and New York. 

About 300 MW of geothermal energy is being developed in California, Nevada, and Idaho. 

• Current leading geothermal technology companies include the following: 

Calpine Corporation 

Caithness Energy 

Cal Energy Company (a subsidiary of Mid American Energy Holding Company) 

Ormat International, Inc. 

Technology History 

• The use of geothermal energy as a source of hot water for spas dates back thousands of years. 

• In 1892, the world's first district heating system was built in Boise, Idaho, as water was piped from 

hot springs to town buildings. Within a few years, the system was serving 200 homes and 40 downtown 

businesses. Today, the Boise district heating system continues to flourish. Although no one imitated 

this system for nearly 70 years, there are now 17 district heating systems in the United States and 

dozens more around the world. 

• The United States’ first geothermal power plant went into operation in 1922 at The Geysers in 

California. The plant was 250 kW, but fell into disuse. 

• In 1960, the country's first large-scale geothermal electricity-generating plant began operation. 

Pacific Gas and Electric operated the plant, located at The Geysers. The resource at The Geysers is dry 

steam. The first turbine produces 11 megawatts (MW) of net power and operated successfully for more 

than 30 years. 

• In 1979, the first electrical development of a water-dominated geothermal resource occurred at the 

East Mesa field in the Imperial Valley in California. 

• In 1980, UNOCAL built the country's first flash plant, generating 10 MW at Brawley, California. 

• In 1981, with a supporting loan from DOE, Ormat International Inc. successfully demonstrated 

binary technology in the Imperial Valley of California. This project established the technical feasibility 

of larger-scale commercial binary power plants. The project was so successful that Ormat repaid the 

loan within a year. 

• By the mid 1980s, electricity was being generated by geothermal power in four western states: 

California, Hawaii, Utah, and Nevada. 

• In the 1990s, the U.S. geothermal industry focused its attention on building power plants overseas, 

with major projects in Indonesia and the Philippines. 

• In 1997, a pipeline began delivering treated municipal wastewater and lake water to The Geysers 

steamfield in California, increasing the operating capacity by 70 MW. 

• In 2000, DOE initiated its GeoPowering the West program to encourage development of 

geothermal resources in the western United States by reducing nontechnical barriers. 

• The DOE Geothermal Program sponsored research that won two R&D awards in 2003, advancing 

this renewable energy. 

12
Technology Future

The levelized cost of electricity (in constant 1997$/kWh) for the two major future geothermal energy 

configurations are projected to be: 

 2000 2010 2020 

Hydrothermal Flash 3.0 2.4 2.1 

Hydrothermal Binary 3.6 2.9 2.7 

 

Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997. 

• New approaches to utilization will be developed, which increase the domestic resource base by a 

factor of 10. 

• Improved methodologies will be developed for predicting reservoir performance and lifetime. 

• Advances will be made in finding and characterizing underground permeability and developing 

low-cost, innovative drilling technologies. 

• Further R&D will reduce capital and operating costs and improve the efficiency of geothermal 

conversion systems. 

• Heat recovery methods will be developed that allow the use of geothermal areas that are deeper, 

less permeable, or dryer than those currently considered as resources. 

• Production will continue at existing geothermal plants, totaling 2.2GW. Ten gigawatts of energy 

may be sourced from geothermal power by 2015, providing sufficient heat and electricity for 7 million 

homes. By 2020, 20 GW of installed capacity from hydrothermal plants and 20 GW from enhanced 

geothermal systems may exist. One hundred gigawatts of future construction potential exists for this 

sector. Direct heat will replace existing systems in 19 western states’ markets. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

13
Geothermal 

Market Data 

Cumulative Installed Capacity Source: U.S. electricity data from EIA, Annual Energy Review 2003, DOE/EIA-0384(2

September 2004), Table 8.11a; world totals from Renewable Energy World/July-Augu

1; 1998 world totals from UNDP World Energy Assessment 2000, Tables 7.20 and 7.2and U.S. and world direct-use heat data from Stefansson and Fridleifsson 1998, “GeoEuropean and World-wide Perspective.” 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Electricity (MWe) 

U.S. 909 1,580 2,666 2,968 2,893 2,893 2,893 2,846 2,79Rest of World 1,191 3,184 3,166 3,829 5,128 5,346 5,18

World Total 2,100 4,764 5,832 6,797 8,021 8,239 7,974

Direct-Use Heat (MWth) U.S. 1,905

Rest of World 7,799World Total 1,950 7,072 8,064 8,664 9,704 11,000 17,17

Cumulative Installed Capacity Source: International Geothermal Association, 

http://iga.igg.cnr.it/index.php 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Electricity (MWe) 

U.S. 2,775 2,817 2,22

Rest of World 3,057 4,016 5,746 

World Total 5,832 6,833 7,974 

Direct-Use Heat (MWth) 

U.S. 1,874 3,76

Rest of World 6,730 11,37World Total 8,604 15,14

14
Annual Installed Electric 

Capacity (MWe) 

Source: Renewable Energy Project Information System (REPiS), Version 7, NREL, 2003. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

 U.S. 251.0 352.9 48.6 36.0 59.9 

Cumulative Installed Electric Capacity (MWe) 

Source: Renewable Energy Project Information System (REPiS), Version 7, NREL, 2003. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

 U.S. 802 1,698 2,540 2,684 2,720 2,720 2,720 2,720 2,779 

 * 2003 data not complete as REPiS database is updated through 2002. 

Installed Capacity and Power Generation/Energy Production from Installed Capacity 

Source: Lund and Freeston, World-Wide Direct Uses of Geothermal Energy 2000, Lund and Use in the United States Update: 1995-1999, J. Lund, World Status of Geothermal Energy 

http://www.geothermie.de/europaundweltweit/Lund/wsoge_index.htm, Sifford and Blommqu

Power Production in the United States: A Survey and Update for 1995-1999, and G. Huttrer

Geothermal Power Generation 1995-2000. Proceedings of the World Geothermal Congres

http://geothermal.stanford.edu/wgc2000/SessionList.htm, Kyushu-Tohoku, Japan, May 28-J

Cumulative Installed Capacity 

1980 1985 1990 1995 1996 1997 1998 1999 2000

Electricity (MWe) 

 U.S. 2,369 2,343 2,314 2,284 2,293 2,228 Rest of World 4,464 5,746 World Total 3,887 4,764 5,832 6,833 7,974Direct-Use Heat* (MWth) 

 U.S. 4,200

 Rest of World 12,975 World Total 1,950 7,072 8,064 8,664 16,209 17,175Annual Generation/Energy Production from Cumulative Installed Capacity 

1980 1985 1990 1995 1996 1997 1998 1999 2000

Electricity (Billion kWhe) 

 U.S. 14.4 15.1 14.6 14.7 15.0 15.5

15
 Rest of World 33.8

 World Total 49.3Direct-Use Heat* (TJ)  U.S. 13,890 20,302 21,700 Rest of World 98,551 141,707  World Total 86,249 112,441 162,009 185,139* Direct-use heat includes geothermal heat pumps as well as traditional uses. Geothermal heat pumps account for 1854 MW

6849 MWth (23,214 TJ) in 1999 of the world totals and 3600 MWth (8,800 TJ) in 2000 of the U.S. total. Conversion of GWh 

0.2778 GWh. 

Annual Generation from 

Cumulative Installed Capacity 

Source: U.S. electricity data from EIA, Annual Energy Review 2003, DOE/EIA-0384(2

D.C., September 2004), Table 8.2a; world electricity totals from Renewable Energy W

page 126, Table 2; 1997 world electricity and U.S. and world direct-use heat data from 

Fridleifsson 1998, “Geothermal Energy: European and World-wide Perspective.” 1998 

UNDP World Energy Assessment 2000, Table 7.25; 1995, 2000, and 2003 direct-use electricity world total from International Geothermal Association, http://iga.igg.cnr.it/ind

1980 1985 1990 1995 1996 1997 1998 1999 2000 2

Electricity (Billion kWhe) 

U.S. 5.1 9.3 15.4 13.4 14.3 14.7 14.8 14.8 14.1 

Rest of World 8.9 7.7 3.6 6.6 29.0 31.2 35.2World Total 14 17 19 20 43.8 46 49 49.3 Direct-Use Heat (billion kWhth) U.S. 3.9 4.0 5.6 Rest of World 27.4 31.1 47.3World Total 31.2 35.1 40 53.0 

Annual Geothermal Energy Consumption for Electric Generation (Trillion Btu) 

Source: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C

8.4a. 1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. 110 198 326 280 300 309 311 312 296 Rest of World 

World Total 

16
Annual U.S. Geothermal Heat Pump 

Shipments, by type (units) 

Source: EIA, Renewable Energy Annual 2003, DOE/EIA-0603(2003) (Washington, 

Table 37. 1980 1985 1990 1995 1996 1997 1998 1999 2000 

ARI-320 4,696 4,697 7,772 10,510 7,910 7,808 

ARI-325/330 26,800 25,697 28,335 26,042 31,631 26,219 

Other non-ARI Rated 838 991 1,327 1,714 2,138 1,554 

Totals 32,334 31,385 37,434 38,266 41,679 35,581 * No survey was conducted for 2001. Capacity of U.S. Heat Pump Shipments (Rated Tons) 

Source: EIA, Renewable Energy Annual 2003, DOE/EIA-0603(2003) (Washington, 

Table 38. 1980 1985 1990 1995 1996 1997 1998 1999 2000 

ARI-320 13,120 15,060 24,708 35,776 27,970 26,469 

ARI-325/330 113,925 92,819 110,186 98,912 153,947 130,132 

Other non-ARI Rated 3,935 5,091 6,662 6,758 9,735 7,590 

Totals 130,980 112,970 141,556 141,446 191,652 164,191 1 One Rated Ton of Capacity equals 12,000 Btu's. 

2 No survey was conducted for 2001. 

Annual U.S. Geothermal Heat Pump Shipments by Customer Type and Model Type (units) 

Source: EIA, Renewable Energy Annual 2003, DOE/EIA-0603(2003) (Washington, 

40, REA 2002 Table 40, REA 2001 Table 40, REA 2000 Table 38, REA 1999 Tabl1980 1985 1990 1995 1996 1997 1998 1999 2000 

Exporter 2,276 226 109 6,172 784 

Wholesale Distributor 21,444 29,181 14,377 9,193 9,804 Retail Distributor 8,336 829 3,222 2,555 2,272 Installer 18,762 25,302 18,429 24,917 20,491 End-User 689 657 994 66 63 

Others 13 1,727 1,135 6,259 2,167 

Total 51,520 57,922 38,266 49,162 35,581 

17
Annual U.S. Geothermal Heat Pump 

Shipments by Export & Census Region (units) 

Source: EIA, Renewable Energy Annual 2003, DOE/EIA-0603(2003) (Washington, 

39, REA 2002 Table 39, REA 2001 Table 39, REA 2000 Table 37, REA 1999 Table 1980 1985 1990 1995 1996 1997 1998 1999 2000 

Export 4,090 2,427 481 6,303 1,220 

Midwest 11,874 13,402 12,240 13,112 10,749 Northeast 6,417 9,280 5,403 6,044 4,138 South 25,302 26,788 16,195 20,935 17,403 West 3,837 6,025 3,947 2,768 2,071 Total 51,520 57,922 38,266 49,162 35,581 

Technology Performance 

 Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997 (this 

being updated by DOE and the values most likely will change). 

Efficiency 1980 1990 1995 2000 2005 2010 

Capacity Factor (%) Flashed Steam 89 92 93 95 

Binary 89 92 93 95 Hot Dry Rock 80 81 82 83 

Cost 1980 1990 1995 2000 2005 2010 

Capital Cost ($/kW) Flashed Steam 1,444 1,372 1,250 1,194 

Binary 2,112 1,994 1,875 1,754 Hot Dry Rock 5,519 5,176 4,756 4,312 

Fixed O&M ($/kW-yr) Flashed Steam 96.4 87.1 74.8 66.3 

Binary 87.4 78.5 66.8 59.5 

 Hot Dry Rock 219 207 191 179 

18
Concentrating Solar Power

Technology Description 

Concentrating Solar Power (CSP) systems concentrate solar energy 50 to 5,000 times to produce hightemperature thermal energy, which is used to produce electricity for distributed- or bulk-generation 

power applications. 

System Concepts

• In CSP systems, highly 

reflective sun-tracking 

mirrors produce 

temperatures of 400oC to 

800oC in the working fluid 

of a receiver; this heat is 

used in conventional heat 

engines (steam or gas 

turbines or Stirling engines) 

to produce electricity at 

system solar-to-electric 

efficiencies of up to 30%. 

Systems using advanced 

photovoltaics (PV) cells 

may achieve efficiencies greater than 33%. 

Representative Technologies 

• A parabolic trough system focuses solar energy on a linear oil-filled receiver, which collects heat to 

generate steam and power a steam turbine. When the sun is not shining, steam can be generated with 

fossil fuel to meet utility needs. Plant sizes can range from 10 MWe to 100 MWe. 

• A power tower system uses many large heliostats to focus the solar energy onto a tower-mounted 

central receiver filled with a molten-salt working fluid that produces steam. The hot salt can be stored 

efficiently to allow power production to match utility demand even when the sun is not shining. Plant 

size can range from 30 MWe to 200 MWe. 

• A dish/engine system (see diagram above) uses a dish-shaped reflector to power a small Stirling or 

Brayton engine/generator or a high-concentrator PV module mounted at the focus of the dish. Dishes 

are 2 to 25 kW in size, can be used individually or in small groups, and are easily hybridized with fossil 

fuel. 

Technology Applications 

• Concentrating solar power systems can be sized for village power (10 kilowatts) or grid-connected 

applications (up to 100 megawatts). Some systems use thermal storage during cloudy periods or at 

night. Others can be combined with natural gas such that the resulting hybrid power plants can provide 

higher-value, dispatchable power. 

• To date, the primary use of CSP systems has been for bulk power supply to the southwestern grid. 

However, these systems were installed under very attractive power purchase rates that are not generally 

available today. With one of the best direct normal insolation resources anywhere on Earth, the 

southwestern states are still positioned to reap large and, as yet, largely uncaptured economic benefits 

from this important natural resource. California, Nevada, Arizona, and New Mexico are each exploring 

policies that will nurture the development of their solar-based industries. 

19
• In addition to the concentrating solar power projects under way in this country, a number of 

projects are being developed in India, Egypt, Morocco, and Mexico. In addition, independent power 

producers are in the early stages of design and development for potential parabolic trough and/or power 

tower projects in Greece (Crete) and Spain. Given successful deployment of systems in one or more of 

these initial markets, several domestic project opportunities are expected to follow. 

• Distributed-systems deployment opportunities are emerging for dish-engine systems. Many states 

are adopting green power requirements in the form of “portfolio standards” and renewable energy 

mandates. While the potential markets in the United States are large, the size of developing worldwide 

markets is immense. The International Energy Agency (IEA) projects an increased demand for 

electrical power worldwide more than doubling installed capacity. More than half of this is in 

developing countries; and a large part is in areas with good solar resources, limited fossil fuel supplies, 

and no power distribution network. The potential payoff for dish/engine system developers is the 

opening of these immense global markets for the export of power generation systems. 

Current Status 

• CSP technology is generally still too expensive to compete in widespread domestic markets without 

significant subsidies. Consequently, RD&D goals are to reduce costs of CSP systems to 5¢/kWh to 

8¢/kWh with moderate production levels within five years, and below 5c/kWh at high production 

levels in the long term. 

• Nine parabolic trough plants, with a total rated capacity of 354 MWe, were installed in California 

between 1985 and 1991. Their continuing operation has demonstrated their ability to achieve 

commercial costs of about 12¢/kWh to 14¢/kWh. O&M costs at these plants have declined by 40% due 

to technological improvements, saving the commercial plant operators $50 million. 

• Solar Two, a 10-MWe pilot power tower with three hours of storage, also installed in California, 

provided technical information needed to scale up to a 30-100 MW commercial plant, the first of which 

is now being planned in Spain. 

• A number of prototype dish/Stirling systems are currently operating in Nevada, Arizona, Colorado, 

and Spain. High levels of performance have been established; durability remains to be proven, although 

some systems have operated for more than 10,000 hours. 

• The CSP industry includes 25 companies who design, sell, own, and/or operate energy systems and 

power plants based on the concentration of solar energy. CSP companies include energy utilities, 

independent power producers or project developers, equipment manufacturers, specialized 

development firms, and consultants. While some firms only offer CSP products, many offer related 

energy products and services. Four of the 25 are “Fortune 500 Companies.” Current companies include:

 Duke Solar Energy, LLC Stirling Energy Systems 

 Nexant (a Bechtel Technology & Consulting Company) Science Applications International Corp. 

 The Boeing Company STM Corporation 

 KJC Operating Company WGAssociates 

 SunRay Corporation Morse & Associates 

 Arizona Public Service Corporation United Innovations Inc. 

 Spencer Management Associates Reflective Energies 

 Kearney & Associates Industrial Solar Technologies 

Nagel Pump Spectralab 

Clever Fellows Innovative Consortium Salt River Project 

Array Technologies Energy Laboratories Inc. 

Concentrating Technologies Amonix 

Ed Tek Inc. 

20
Technology History 

Organized, large-scale development of solar collectors began in the United States in the mid-1970s 

under the Energy Research and Development Administration (ERDA) and continued with the 

establishment of the U.S. Department of Energy (DOE) in 1978. 

 

Troughs: 

• Parabolic trough collectors capable of generating temperatures greater than 500oC (932 F) were 

initially developed for industrial process heat (IPH) applications. Acurex, SunTec, and Solar Kinetics 

were the key parabolic trough manufacturers in the United States during this period. 

• Parabolic trough development also was taking place in Europe and culminated with the 

construction of the IEA Small Solar Power Systems (SSPS) Project/Distributed Collector System in 

Tabernas, Spain, in 1981. This facility consisted of two parabolic trough solar fields – one using a 

single-axis tracking Acurex collector and one the double-axis tracking parabolic trough collectors 

developed by M.A.N. of Munich, Germany. 

• In 1982, Luz International Limited (Luz) developed a parabolic trough collector for IPH 

applications that was based largely on the experience that had been gained by DOE/Sandia and the 

SSPS projects. 

• Southern California Edison (SCE) signed a power purchase agreement with Luz for the Solar 

Electric Generating System (SEGS) I and II plants, which came online in 1985. Luz later signed a 

number of Standard Offer (SO) power purchase contracts under the Public Utility Regulatory Policies 

Act (PURPA), leading to the development of the SEGS III through SEGS IX projects. Initially, the 

plants were limited by PURPA to 30 MW in size; later this limit was raised to 80 MW. In 1991, Luz 

filed for bankruptcy when it was unable to secure construction financing for its 10th plant (SEGS X). 

• The 354 MWe of SEGS trough systems are still being operated today. Experience gained through 

their operation will allow the next generation of trough technology to be installed and operated much 

more cost-effectively. 

Power Towers: 

• A number of experimental power tower systems and components have been field-tested around the 

world in the past 15 years, demonstrating the engineering feasibility and economic potential of the 

technology. 

• Since the early 1980s, power towers have been fielded in Russia, Italy, Spain, Japan, and the 

United States. 

• In early power towers, the thermal energy collected at the receiver was used to generate steam 

directly to drive a turbine generator. 

• The U.S.-sponsored Solar Two was designed to demonstrate the dispatchability provided by 

molten-salt storage and to provide the experience necessary to lessen the perception of risk from these 

large systems. 

• U.S. industry is currently pursuing a subsidized power tower project opportunity in Spain. This 

project, dubbed “Solar Tres,” represents a 4x scale-up of the Solar 2 design. 

Dish/Engine Systems: 

• Dish/engine technology is the oldest of the solar technologies, dating back to the 1800s when a 

number of companies demonstrated solar-powered steam Rankine and Stirling-based systems. 

• Development of modern technology began in the late 1970s and early 1980s. This technology used 

directly illuminated, tubular solar receivers, a kinematic Stirling engine developed for automotive 

applications, and silver/glass mirror dishes. Systems, nominally rated at 25 kWe, achieved solar-toelectric conversion efficiencies of around 30 percent. Eight prototype systems were deployed and 

operated on a daily basis from 1986 through 1988. 

• In the early 1990s, Cummins Engine Company attempted to commercialize dish/Stirling systems 

21
based on free-piston Stirling engine technology. Efforts included a 5 to 10 kWe dish/Stirling system for 

remote power applications, and a 25 kWe dish/engine system for utility applications. However, largely 

because of a corporate decision to focus on its core diesel-engine business, Cummins canceled their 

solar development in 1996. Technical difficulties with Cummins' free-piston Stirling engines were 

never resolved. 

• Current dish/engine efforts are being continued by three U.S. industry teams - Science Applications 

International Corp. (SAIC) teamed with STM Corp., Boeing with Stirling Energy Systems, and WG 

Associates with Sunfire Corporation. SAIC and Boeing together have five 25kW systems under test 

and evaluation at utility, industry, and university sites in Arizona, California, and Nevada. WGA has 

two 10kW systems under test in New Mexico, with a third off-grid system being developed in 2002 on 

an Indian reservation for water-pumping applications. 

Technology Future

The levelized cost of electricity (in constant 1997$/kWh) for the three CSP configurations are projected 

to be: 

 2000 2010 2020

Trough 9.5 5.4 4.4 

Power Tower 9.5 4.8 3.6 

Dish/Engine 17.9 6.1 5.5 

 Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997 for Dish/Engine, 

and Program values for Trough and Power Tower. 

• RD&D efforts are targeted to improve performance and lifetime, reduce manufacturing costs with 

improved designs, provide advanced designs for long-term competitiveness, and address barriers to 

market entry. 

• RD&D goals are to reduce the cost of CSP systems to 5 to 8¢/kWh within five years at moderate 

production levels. Long-run goals are to reduce costs below 4¢/kWh at high production levels. 

• Improved manufacturing technologies are needed to reduce the cost of key components, especially 

for first-plant applications where economies of scale are not yet available. 

• Demonstration of Stirling engine performance and reliability in the field are critical to the success 

of dish/engine systems. 

• DOE expects Dish/Stirling systems to be available by 2005, after deployment and testing of 1 MW 

(40 systems) during the next two years. 

• Key DOE program activities are targeted to support the next commercial opportunities for these 

technologies, demonstrate improved performance and reliability of components and systems, reduce 

energy costs, and develop advanced systems and applications. 

• The successful conclusion of Solar Two sparked worldwide interest in power towers. As Solar Two 

completed operations, an international consortium led by U.S. industry including Bechtel and Boeing 

(with technical support from Sandia National Laboratories), formed to pursue power tower plants 

worldwide, especially in Spain (where special solar premiums make the technology cost-effective), but 

also in Egypt, Morocco, and Italy. Their first commercial power tower plant is planned to be four times 

the size of Solar Two (about 40 MW equivalent, utilizing storage to power a 15MW turbine up to 24 

hours per day). 

• The World Bank’s Solar Initiative is pursuing CSP technologies for less-developed countries. The 

World Bank considers CSP as a primary candidate for Global Environment Facility funding, which 

could total $1B to $2B for projects during the next two years. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

22
Concentrating Solar Power 

Market Data 

U.S. Installations (electric only) Source: Renewable Energy Project Information System (REPiS), Version 

7, NREL, 2003, and Renewable Energy Technology Characterizations, EPRI TR-109496. 

Cumulative (MW) 1980 1985 1990 1995 1996 1997 1998 1999 200

 U.S. 0 24 274 354 364 364 364 364 35

 Power Tower 0 10 0 0 10 10 10 10  Trough 0 14 274 354 354 354 354 354 35 Dish/Engine 0 0 0 0 0 0 0.125 0.125 0.12

Annual Generation from Cumulative Installed Capacity (Billion kWh) 

Source: EIA, Annual Energy Outlook 1998-2004 Table A17, Renewable ResourceSupply, 1993 Table 4. 

1980 1985 1990 1995 1996 1997 1998 1999 200

 U.S. 1* 0.82 0.90 0.89 0.89 0.87 0.4* Includes both solar thermal and less than 0.02 billion kilowatthours grid-connected photovoltaic generation. Annual U.S. Solar Thermal Shipments (Thousand Square Feet) 

Source: EIA - Annual Energy Review 2003 Table 10.3 and Renewable Energy Annu

1980 1985 1990 1995 1996 1997 1998 1999 2000 200

 Total 1 19,398 N/A 11,409 7,666 7,616 8,138 7,756 8,583 8,354 11,18 Imports 235 N/A 1,562 2,037 1,930 2,102 2,206 2,352 2,201 3,50 Exports 1,115 N/A 245 530 454 379 360 537 496 841 Total shipments as reported by respondents include all domestic and export shipments and may include imports that subsequently were shipped to domestic or to foreign customers. No data are available for 1985. 

23
Technology Performance 

Efficiency Source: Renewable Energy Technology Characterizations, EPRI TR-10949

currently being updated by DOE, and the values most likely will change), anHank Price of NREL for Trough technologies and Scott Jones of Sandia NatPower Towers in 2001. 

1980 1990 1995 2000 2005 20

 Capacity Factor (%) Power Tower 20.0 43.0 44.0 65 Trough 34.0 33.3 41.7 51 Dish 12.4 50.0 50.0 50 Solar to Electric Eff. (%) Power Tower 8.5 15.0 16.2 17 Trough 10.7 13.1 13.9 14 Dish/Engine 

Cost* 1980 1990 1995 2000 2005 20

 Total ($/kWp) Power Tower 1,747 1,294 9 Trough 4,033 2,103 1,633 1,2 Dish/Engine 12,576 5,191 2,831 1,3 Total ($/kWnameplate) Power Tower 3,145 2,329 2,6 Trough 4,033 3,154 2,988 2,7 Dish/Engine 12,576 5,691 3,231 1,6 O&M ($/kWh) Power Tower 0.171 0.018 0.006 0.0

 Trough 0.025 0.017 0.013 0.0 Dish/Engine 0.210 0.037 0.023 0.0Levelized Cost of Energy Power Tower 0.101 0.066 0.0 ($/kWh) Trough 0.160 0.101 0.077 0.0 Dish/Engine 0.179 0.0

* Cost data for trough and power tower technologies are from 2001 revisions (in 2001$). Dish/Engine data for $/kWp exclu

system and $/kWnameplate includes hybrid costs (in 1997$). 

24
Photovoltaics

Technology Description 

Photovoltaic (PV) arrays convert sunlight to electricity without moving parts and without producing 

fuel wastes, air pollution, or greenhouse gases (GHGs). Using solar PV for electricity and eventually 

transportation (from hydrogen production) will help reduce CO2 worldwide. 

System Concepts

• Flat-plate PV arrays use global sunlight; concentrators use direct sunlight. Modules are mounted on 

a stationary array or on single- or dual-axis sun trackers. Arrays can be ground-mounted or on all types 

of buildings and 

structures (e.g., see 

semi-transparent solar 

canopy, right). PV dc 

output can be 

conditioned into gridquality ac electricity, 

or dc can be used to 

charge batteries or to 

split water to produce 

H2. 

 

Representative 

Technologies 

• Flat-plate cells are either constructed from crystalline silicon cells, or from thin films using 

amorphous silicon. Other materials such as copper indium diselinide (CIS) and cadmium telluride also 

hold promise as thin-film materials. The vast majority of systems installed today are in flat-plate 

configurations where multiple cells are mounted together to form a module. These systems are 

generally fixed in a single position, but can be mounted on structures that tilt toward the sun on a 

seasonal basis, or on structures that roll east to west over the course of the day. 

• Photovoltaic concentrator systems use optical concentrators to focus direct sunlight onto solar cells 

for conversion to electricity. A complete concentrating system includes concentrator modules, support 

and tracking structures, a power-processing center, and land. PV concentrator module components 

include solar cells, an electrically isolating and thermally conducting housing for mounting and 

interconnecting the cells, and optical concentrators. The solar cells in today's concentrators are 

predominantly silicon, although gallium arsenide-based (GaAs) solar cells may be used in the future 

because of their high-conversion efficiencies. The housing places the solar cells at the focus of the 

optical concentrator elements and provides means for dissipating excess heat generated in the solar 

cells. The optical concentrators are generally Fresnel lenses but also can be reflectors. 

Technology Applications 

• PV systems can be installed as either grid supply technologies or as customer-sited alternatives to 

retail electricity. As suppliers of bulk grid power, PV modules would typically be installed in large 

array fields ranging in total peak output from a few megawatts on up. Very few of these systems have 

been installed to-date. A greater focus of the recent marketplace is on customer-sited systems, which 

may be installed to meet a variety of customer needs. These installations may be residential-size 

systems of just one kilowatt, or commercial-size systems of several hundred kilowatts. In either case, 

PV systems meet customer needs for alternatives to purchased power, reliable power, protection from 

price escalation, desire for green power, etc. Interest is growing in the use of PV systems as part of the 

building structure or façade (“building integrated”). Such systems use PV modules designed to look 

like shingles, windows, or other common building elements. 

25
• PV systems are expected to be used in the United States for residential and commercial buildings; 

distributed utility systems for grid support; peak power shaving, and intermediate daytime load 

following; with electric storage and improved transmission, for dispatchable electricity; and H2

production for portable fuel. 

• Other applications for PV systems include electricity for remote locations, especially for billions of 

people worldwide who do not have electricity. Typically, these applications will be in hybrid minigrid 

or battery-charging configurations. 

• Almost all locations in the United States and worldwide have enough sunlight for PV (e.g., U.S. 

sunlight varies by only about 25% from an average in Kansas). 

• Land area is not a problem for PV. Not only can PV be more easily sited in a distributed fashion 

than almost all alternatives (e.g., on roofs or above parking lots), a PV-generating station 140 km-by140 km sited at an average solar location in the United States could generate all of the electricity 

needed in the country (2.5 × 106

 GWh/year), assuming a system efficiency of 10% and an area packing 

factor of 50% (to avoid self-shading). This area (0.3% of U.S.) is less than one-third of the area used 

for military purposes in the United States. 

Current Status 

• The cost of PV-generated electricity has dropped 15- to 20-fold; and grid-connected PV systems 

currently sell for about $5–$8/Wp (20 to 32¢/kWh), including support structures, power conditioning, 

and land. They are highly reliable and last 20 years or longer. 

• Crystalline silicon is widely used and the most commercially mature photovoltaic material. Thinfilm PV modules currently in production include three based on amorphous silicon, cadmium telluride, 

and CIS alloys. 

• About 288 MW of PV were sold in 2000 (more than $2 billion worth) and 510 MW of PV were 

sold in 2002; total installed PV is more than 2 GW. The U.S. world market share is about 20%. Annual 

market growth for PV has been about 25% as a result of reduced prices and successful global 

marketing. Specifically, sales grew 36% in 2001 and 31% in 2002. Hundreds of applications are costeffective for off-grid needs. Almost two-thirds of U.S.-manufactured PV is exported. However, the 

fastest growing segment of the market is grid-connected PV, such as roof-mounted arrays on homes 

and commercial buildings in the United States. California is subsidizing PV systems because it is 

considered cost-effective to reduce their dependence on natural gas, especially for peak daytime loads 

for air-conditioning, which matches PV output. 

• Highest efficiency for wafers of single-crystal or polycrystalline silicon is 25%, and for commercial 

modules is 13%–17%. Silicon modules currently cost about $2/Wp to manufacture. 

• In the past few years, world record solar cell sunlight-to-electricity conversion efficiencies were set 

by federally funded universities, national laboratories, or industry in copper indium gallium diselenide 

(19% cells and 13% modules) and cadmium telluride (16% cells, 11% modules). Cell and module 

efficiencies for these technologies have increased more than 50% in the past decade. Efficiencies for 

commercial thin-film modules are 5%–11%, with the best cells offering 12-19% efficiency. A new 

generation of thin-film PV modules is going through the high-risk transition to first-time and largescale manufacturing. If successful, market share could increase rapidly. 

• Highest efficiencies for single-crystal Si and multijunction gallium arsenide (GaAs)-alloy cells for 

concentrators are 25%–34%; and for commercial modules are 15%–17%. Prototype systems are being 

tested in the U.S. desert SW. 

• Current leading PV companies in 2000 and associated production of cells/modules are listed below: 

Top PV Producers (2002) 

U.S. Production World Production

 MW MW 

Sharp - 198.0 

Shell Solar 52.0 73.0 

26
Kyocera - 72.0 

BP Solar 13.4 70.2 

RWE (ASE) 4.0 44.0 

Mitsubishi - 42.0 

Isofoton - 35.2 

Sanyo - 35.0 

Q-Cells - 28.0 

Photowatt - 20.0 

AstroPower 17.0 17.0 

USSC 7.0 

Global Solar 3.0 - 

First Solar 3.0 - 

Evergreen 

Solar 2.8 - 

Other* 2.0 - 

 

Total 104.22 632.4 

World Total - 744.1 

Source: US: PV News, Vol. 23, No. 3, Page 2; World: PV News, Vol. 23, No. 4, Page 2 

Technology History 

• French physicist Edmond Becquerel first described the photovoltaic (PV) effect in 1839, but it 

remained a curiosity of science for the next three quarters of a century. At only 19, Becquerel found 

that certain materials would produce small amounts of electric current when exposed to light. The 

effect was first studied in solids, such as selenium, by Heinrich Hertz in the 1870s. Soon afterward, 

selenium PV cells were converting light to electricity at more than 1 percent efficiency. As a result, 

selenium was quickly adopted in the emerging field of photography for use in light-measuring devices. 

• Major steps toward commercializing PV were taken in the 1940s and early 1950s, when the 

Czochralski process was developed for producing highly pure crystalline silicon. In 1954, scientists at 

Bell Laboratories depended on the Czochralski process to develop the first crystalline silicon 

photovoltaic cell, which had an efficiency of 4%. Although a few attempts were made in the 1950s to 

use silicon cells in commercial products, it was the new space program that gave the technology its first 

major application. In 1958, the U.S. Vanguard space satellite carried a small array of PV cells to power 

its radio. The cells worked so well that PV technology has been part of the space program ever since. 

• Even today, PV plays an important role in space, supplying nearly all power for satellites. The 

commercial integrated circuit technology also contributed to the development of PV cells. Transistors 

and PV cells are made from similar materials and operate on similar physical mechanisms. As a result, 

advances in transistor research provided a steady flow of new information about PV cell technology. 

(Today, however, this technology transfer process often works in reverse, as advances in PV research 

and development are sometimes adopted by the integrated circuit industry.) 

• Despite these advances, PV devices in 1970 were still too expensive for most "down-to-Earth" 

uses. But, in the mid-1970s, rising energy costs, sparked by a world oil crisis, renewed interest in 

making PV technology more affordable. Since then, the federal government, industry, and research 

organizations have invested billions of dollars in research, development, and production. A thriving 

industry now exists to meet the rapidly growing demand for photovoltaic products. 

27
Technology Future

The levelized cost of electricity (in constant 1997$/kWh) for PV are projected to be: 

 2000 2010 2020 

Utility-owned Residential 29.7 17.0 10.2 

(crystalline Si) 

Utility-Scale Thin-Film 29.0 8.1 6.2 

Concentrator 24.4 9.4 6.5 

 Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997. 

(Note that this document is currently being updated by DOE, and the values most likely will change). 

• Crystalline Silicon - Most PV systems installed to-date have used crystalline silicon cells. That 

technology is relatively mature. In the future, cost-effectiveness will be achieved through incremental 

efficiency improvements, enhanced yields, and advanced lower-cost manufacturing techniques. 

• Even though some thin-film modules are now commercially available, their real commercial impact 

is only expected to become significant during the next three to 10 years. Beyond that, their general use 

should occur in the 2005-2015 time frame, depending on investment levels for technology development 

and manufacture. 

• Thin films using amorphous silicon, which are a growing segment of the U.S. market, have several 

advantages over crystalline silicon. It can be manufactured at lower cost, is more responsive to indoor 

light, and can be manufactured on flexible or low-cost substrates. Improved semiconductor deposition 

rates will reduce manufacturing costs in the future. Other thin-film materials will become increasingly 

important in the future. In fact, the first commercial modules using indium gallium diselinide thin-film 

devices were produced in 2000. Improved manufacturing techniques and deposition processes will 

reduce costs and help improve efficiency. 

• Substantial commercial interest exists in scaling-up production of thin films. As thin films are 

produced in larger quantity, and as they achieve expected performance gains, they will become more 

economical for the whole range of applications. 

• Multijunction cells with efficiencies of 38% at very high concentrations are being developed. 

• Manufacturing research and supporting technology development hold important keys to future cost 

reductions. Large-scale manufacturing processes will allow major cost reductions in cells and modules. 

Advanced power electronics and non-islanding inverters will lessen barriers to customer adoption and 

utility interface. 

• A unique multijunction GaAs-alloy cell developed at NREL was spun off to the space power 

industry, leading to a record cell (34%) and a shared R&D100 Award for NREL/Spectrolab in 2001. 

This device configuration is expected to dominate future space power for commercial and military 

satellites. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003 

28
Photovoltaics 

Market Data 

PV Cell/Module Production (Shipments) 

Source: PV News, Vol. 15, No. 2, Feb. 1996; Vol. 16, No. 2, Feb. 1997; Vol. 20, No. 2, Feb

No. 5, May 2003 and Volume 23, No. 4, April 2004. Paul Maycock, www.pvenergy.com 

Annual (MW) 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 U.S. 3 8 15 35 39 51 54 61 75 100 Japan 1 10 17 16 21 35 49 80 129 171 Europe 0 3 10 20 19 30 34 40 61 87 Rest of World 0 1 5 6 10 9 19 21 23 33 World Total 4 23 47 78 89 126 155 201 288 391 Cumulative (MW) 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 U.S. 5 45 101 219 258 309 363 424 499 599 Japan 1 26 95 185 206 241 290 370 499 670 Europe 1 13 47 136 155 185 219 259 320 407 Rest of World 0 3 20 45 55 65 83 104 127 160 World Total 7 87 263 585 674 800 954 1,156 1,444 1,835 U.S. % of World Sales 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 Annual 71% 34% 32% 44% 44% 41% 35% 30% 26% 26% Cumulative 75% 52% 39% 37% 38% 39% 38% 37% 35% 33% 

Annual Capacity (Shipments retained, MW)* 

Source: Strategies Unlimited

1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. 1.4 4.2 5.1 8.4 9.2 10.5 13.6 18.4 21.3 Total World 3 15 39 68 79 110 131 170 246 

*Excludes indoor consumer (watches/calculators). 

29
Cumulative Capacity 

(Shipments retained, MW)* 

Source: Strategies Unlimited

1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. 3 23 43 76 85 96 109 128 149

Total World 6 61 199 474 552 663 794 964 1,210

*Excludes indoor consumer (watches/calculators).

U.S. Shipments (MW) Source: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., Septem

Tables 10.5 and 10.6, and EIA, Renewable Energy Annual 2003, DOE/EIA-0603(2003) (Wa

December 2004) Table 26. 

Annual Shipments 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 Total 5.8 13.8 31.1 35.5 46.4 50.6 76.8 88.2 97.7 

Imports 0.3 1.4 1.3 1.9 1.9 1.9 4.8 8.8 10.2 Exports 1.7 7.5 19.9 22.4 33.8 35.5 55.6 68.4 61.4 

Domestic Total On-Grid* 0.4 0.2 1.7 1.8 2.2 4.2 6.9 4.9 10.1 Domestic Total Off-Grid* 3.7 6.1 9.5 11.2 10.3 10.8 14.4 15.0 26.2 

Cumulative Shipments (since 1982) 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Total 35.2 84.7 193.3 228.8 275.2 325.7 402.5 490.7 588.4 Imports 1.0 5.6 14.3 16.2 18 19.9 24.7 33.5 43.7 Exports 5.7 32.9 104 126.5 160.3 195.8 251.3 319.7 381.0 Domestic Total On-Grid* 2.9 4.7 8.2 10.0 12.2 16.5 23.3 28.2 38.3 Domestic Total Off-Grid* 26.6 47.2 81.1 92.3 102.7 113.5 127.9 142.8 169.0 * Domestic Totals include imports and exclude exports. NA = Not Available; 2003 data not available at time of publication U.S. Shipments (MW) Source: Renewable Energy World, July-August 2003, Volume 6, Number 4, and PV News, V

May 2004 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Total 34.8 38.9 51.0 53.7 60.8 75.0 100.3 

Imports 2.0 4.0 5.0 Exports 24.0 25.1 36.3 37.9 39.8 55.0 73.3 

30
Annual U.S. Installations 

(MW) 

Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United S

by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, Table 1. http://wwservices.nl/iea-pvps/nsr02/download/usa.pdf; and PV News, Vol. 23 No. 5. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Grid-Connected Distributed 1.5 2.0 2.0 2.2 3.7 5.5 12.0 Off-Grid Consumer 3.5 4.0 4.2 4.5 5.5 6.0 7.0 Government 0.8 1.2 1.5 1.5 2.5 2.5 1.0 Off-Grid Industrial/Commercial 4.0 4.4 4.8 5.2 6.5 7.5 9.0 Consumer (<40 w) 2.0 2.2 2.2 2.4 2.5 2.5 3.0 Central Station 0 0 0 0 0 0 0 Total 11.8 13.8 14.7 15.8 20.7 24.0 32.0 Cumulative U.S. Installations* (MW) 

Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United S

by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, Table 1 http://www.oja-services.nl/iea-pvps/nsr02/usa2.htm. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Off-grid Residential 19.3 23.3 27.5 32.0 37.5 43.5 50.5 Off-grid Nonresidential 25.8 30.2 35.0 40.2 46.7 55.2 64.7 On-grid Distributed 9.7 11.0 13.7 15.9 21.1 28.1 40.6 On-grid Centralized 12.0 12.0 12.0 12.0 12.0 12.0 12.0 Total 66.8 76.5 88.2 100.1 117.3 138.8 167.8 * Excludes installations less than 40kW.

Annual World Installations (MW) 

Source: Renewable Energy World, July-August 2003, Volume 6, Number 4. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Consumer Products 16 22 26 30 35 40 45 U.S. Off-Grid Residential 3 8 9 10 13 15 19 World Off-Grid Rural 6 15 19 24 31 38 45 Communications/ Signal N/A N/A 14 N/A 23 28 31 35 40 46 PV/Diesel, Commercial 7 12 16 20 25 30 36 Grid-Conn Res., Commercial 1 7 27 36 60 120 199 Central Station (>100kW) 1 2 2 2 2 5 5 Total 48 89 127 153 201 288 395 

31
Annual U.S. Shipments by 

Cell Type (MW) 

Source: PV News, Vol. 15, No. 2, Feb. 1996; Vol. 16, No. 2, Feb. 1997; Vol. 17, No. 2, Feb

No. 2, Feb. 1999; Vol. 19, No. 3, March 2000; Vol. 20, No. 3, March 2001; Vol. 21, No. 3, Ma22, No. 5, May 2003; and Renewable Energy World, July-August 2003, Volume 6, Number 4

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Single Crystal 22.0 24.1 31.8 30.0 36.6 44.0 63.0 Flat-Plate Polycrystal (other than ribbon) 9.0 10.3 14.0 14.7 16.0 17.0 20.6 Amorphous Silicon 1.3 1.1 2.5 3.8 5.3 6.5 7.3 Crystal Silicon Concentrators 0.3 0.7 0.7 0.2 0.5 0.5 0.5 Ribbon Silicon N/A N/A N/A 2.0 3.0 4.0 4.0 4.2 5.0 6.9 Cadmium Telluride 0.1 0.4 0 0 0 0 0.6 Microcrystal SI/Single SI 0SI on Low-Cost-Sub 0.1 0.3 0.5 1.0 2.0 2.0 1.7 A-SI on Cz Slice 00 Total 34.8 39.9 53.5 53.7 64.6 75 100.6 Annual World Shipments by Cell Type (MW) 

Source: PV News, Vol. 15, No. 2, Feb. 1996; Vol. 16, No. 2, Feb. 1997; Vol. 17, No. 2, Feb

No. 2, Feb. 1999; Vol. 19, No. 3, March 2000; Vol. 20, No. 3, March 2001; Vol. 21, No. 3, Ma22, No. 5, May 2003; and Renewable Energy World, July-August 2003, Volume 6, Number 4

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Single Crystal 46.7 48.5 62.8 59.8 73 89.7 150.41 Flat-Plate Polycrystal 20.1 24 43 66.3 88.4 140.6 278.9 Amorphous Silicon 9.1 11.7 15 19.2 23.9 27 28.01 Crystal Silicon Concentrators 0.3 0.7 0.2 0.2 0.5 0.5 0.5 Ribbon Silicon N/A N/A N/A 2 3 4 4 4.2 14.7 16.9 Cadmium Telluride 1.3 1.6 1.2 1.2 1.2 1.2 2.1 Microcrystal SI/Single SI 3.7 SI on Low-Cost-Sub 0.1 0.3 0.5 1 2 2 1.7 A-SI on Cz Slice 8.1 12 30 Total 79.5 89.8 126.7 151.7 201.3 287.7 512.22 

32
Annual U.S. Shipments by 

Cell Type (MW) 

Source: EIA, Solar Collector Manufacturing Activity annual reports, 1982-1992 and EIA, Ren

Annual 1997, Table 27, REA 2000 Table 26, REA 2002, Table 28. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Single-Crystal Silicon 19.9 21.7 30 30.8 47.2 51.9 54.7 Cast and Ribbon Crystalline Silicon 9.9 12.3 14.3 16.4 26.2 33.2 29.9 Crystalline Silicon Total 5.5 12.5 29.8 34 44.3 47.2 73.5 85.2 84.7 Thin-Film Silicon N/A 0.3 1.3 1.3 1.4 1.9 3.3 3.3 2.7 12.5 Concentrator Silicon 0.1 0.2 0.2 0.1 0.1 0.3 0.5 Other Total 5.8 13.8 31.2 35.6 46.3 50.6 76.8 88.2 97.7 Annual Grid-Connected Capacity (MW) 

Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United S

by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, derived from Tabhttp://www.oja-services.nl/iea-pvps/nsr02/usa2.htm. Japan data from PV News, Vol. 23, No. 2004. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. 1.3 2.7 2.2 5.2 7.0 12.5Japan 3.9 7.5 19.5 24.1 57.7 74.4 91.0 Note: Japan data not necessarily grid-connected Cumulative GridConnected Capacity (MW) Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United S

by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, derived from Tabhttp://www.oja-services.nl/iea-pvps/nsr02/usa2.htm. Japan data from PV News, Vol. 23, No. 2004. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. 21.7 23.0 25.7 27.9 33.1 40.1 52.6Japan 5.8 13.3 32.8 56.9 114.6 189.0 280.0 Japan Grid-Connected Capacity (MW) 

Source: IEA Photovoltaic Power Systems Program, National Survey Report of PV Power Ap

Japan 2002, http://www.oja-services.nl/iea-pvps/nsr02/jpn2.htm Table 1. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Annual 6.0 9.7 22.6 34.7 71.3 114.8 119.3 Cumulative 13.7 23.4 46.0 80.7 151.9 266.7 386.0 

33
Annual U.S.-Installed Capacity (MW) Source: Renewable Electric Plant Information System (REPiS), Version 7, NRE

Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 2000  California 0.034 0.016 0.720 0.900 0.606 0.577 2.993 5.833  Arizona 0.004 0.026 0.067 0.724 0.301 0.574 0.177  New York 0.013 0.067 0.425 0.021 0.246 0.041 0.377  Ohio 0.001 0.001 0.010 0.144  Hawaii 0.000 0.046 0.008 0.291 0.113 0.250  Texas 0.006 0.015 0.002 0.008 0.010 0.133 0.248 0.089  Colorado 0.018 0.100 0.006 0.132 0.344 0.137  Georgia 0.352 0.019 0.221  Florida 0.009 0.008 0.018 0.036 0.047 0.106 0.202  Illinois 0.002 0.005 0.034 0.043  Total U.S. 0.015 0.078 0.049 1.029 2.131 1.670 1.899 5.140 8.244 2003 data not complete as REPiS database is updated through 2002. Cumulative U.S.-Installed Capacity (MW) Source: Renewable Electric Plant Information System (REPiS), Version 7, NRE Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 2000  California 0.002 1.369 2.803 6.495 7.396 8.002 8.579 11.572 17.405  Arizona 0.008 0.032 0.048 0.097 0.164 0.888 1.190 1.764 1.941  New York 0 0 0.013 0.226 0.650 0.671 0.917 0.958 1.334  Ohio 0 0 0 0 0 0.001 0.002 0.012 0.155  Hawaii 0 0.014 0.033 0.033 0.079 0.087 0.378 0.491 0.741  Texas 0.006 0.021 0.366 0.437 0.437 0.446 0.579 0.828 0.917  Colorado 0 0 0.010 0.040 0.140 0.146 0.278 0.622 0.759  Georgia 0 0 0 0 0.352 0.352 0.352 0.371 0.592  Florida 0.009 0.093 0.117 0.135 0.135 0.171 0.218 0.325 0.527  Illinois 0 0 0.021 0.021 0.021 0.023 0.029 0.062 0.105  Total U.S. 1 0.025 2.104 4.170 8.560 10.691 12.362 14.261 19.401 27.645 1 There are an additional 3.4 MW of photovoltaic capacity that are not accounted for here because they have no specific on

2003 data not complete as REPiS database is updated through 2002. 

34
Technology Performance 

 Source: Renewable Energy Technology Characterizations, EPRI TR-109496, 1997. 

 (Note that this document is currently being updated by DOE, and the values most likely 

Efficiency 1980 1990 1995 2000 2005 2

Cell (%) Crystalline Silicon 24.0 24.7  Thin Film 18.0 19.0 20.0 2 Concentrator 20.0 23.0 26.0 3Module (%) Crystalline Silicon 14.0 16.0 17.0  Thin Film N/A N/A 10.0 12.0 15.0  Concentrator System (%) Crystalline Silicon 11.3 13.1 14.1  Thin Film 4.8 7.2 8.8  Concentrator 13.8 15.1 17.1 2

Cost 1980 1990 1995 2000 2005 2

Module ($/Wp) Crystalline Silicon 3.8 3.0 2.3  Thin Film 3.8 2.2 1.0  Concentrator 1.8 1.5 0.7 BOS ($/Wp) Crystalline Silicon 2.7 2.1 1.6  Thin Film 3.7 2.1 1.3  Concentrator N/A N/A 3.6 2.7 1.2 Total ($/Wp) Crystalline Silicon * 6.5 5.1 3.9  Thin Film 7.5 4.3 2.3  Concentrator 7.6 4.0 2.0 O&M ($/kWh) Crystalline Silicon 0.008 0.007 0.006 0 Thin Film 0.023 0.008 0.003 0 Concentrator 0.047 0.020 0.010 0.

* Range in total capital cost for crystalline silicon in 2000 is $5.1/Wp to $9.1/Wp depending on market supply and demand. 

Factors Associated with Photovoltaic System Costs, June 2001, NREL/TP 620.29649, Page 3).

35
36
Wind Energy

Technology Description 

Wind-turbine technology converts the kinetic energy in the wind to mechanical energy and ultimately 

to electricity. Grid-connected wind power reduces GHG emissions by displacing the need for natural 

gas- and coal-fired generation. Village and off-grid applications are important for displacing diesel 

generation and for improving quality of life, especially overseas. 

System Concepts

• The principle of wind energy conversion is simple: Wind 

passing over the blade creates lift, producing a torque on the rotor 

shaft that turns a gearbox. The gearbox is coupled to an electric 

generator that produces power at the frequency of the host power 

system. Some new innovative designs use low-speed generators, 

which eliminate the need for a gearbox. 

 

Representative Technologies 

• Two major design approaches are being used: (1) typical of 

historic European technology—three-bladed, up-wind, stiff, 

heavy machines that resist cyclic and extreme loads, and (2) lightweight, flexible machines that bend 

and absorb loads, primarily being developed by U.S. designers. Several alternative configurations 

within each approach are being pursued.

Technology Applications 

• Thirty-seven states have land area with good winds (13 mph annual average at 10 m height, wind 

Class 4, or better). 

• For wind-farm or wholesale power applications, the principal competition is natural gas for new 

construction and natural gas in existing units for fuel saving. Utility restructuring is a critical challenge 

to increased deployment in the near-term because it emphasizes short-term, low capital-cost 

alternatives and lacks public policy to support deployment of sustainable technologies such as wind 

energy. 

Current Status 

• Wind technology is competitive today in bulk power markets with support from the production tax 

credit, and in high-value niche applications or markets that recognize noncost attributes. 

• Current performance is characterized by levelized costs of 4 to 6¢/kWh (depending on resource 

intensity and financing structure), capacity factors of 30 to 40 percent, availability of 95 to 98%, total 

installed project costs (“overnight” – not including construction financing) of $800 to $1,100/kW, and 

efficiencies of 65% to 75% of the theoretical (Betz limit) maximum. 

• The worldwide annual market growth rate for wind technology is at a level of 30% with new 

markets opening in many developing countries. Domestic public interest in environmentally 

responsible electric generation technology is reflected by new state energy policies and in the success 

of “green marketing” of wind power across the country. 

• Preliminary estimates are that installed capacity at the end of 2001 was 4,260 MW in the United 

States, and 23,300 MW worldwide; compared to 2,550 MW in the United States and 17,653 worldwide 

in 2000; and 2,450 MW in the United States and 13,598 MW worldwide in 1999. 

Wind installations have grown in the United States at an average rate of 15% in the past ten years. 

Installed capacity expanded by nearly 10% in the United States during 2002 to 4685 MW, with 410 

MW of new equipment going into use that year. Worldwide installations currently total 39 GW. 

• U.S. energy generation from wind was nearly 11 TWh out of a worldwide total of 69 TWh in 2003 

up from 4.5 TWh out of an approximate total of 26 TWh in 1999. 

37
• The top ten states had between 2,000 MW and 176 MW of large wind-turbine capacity at the end of 

2003. 

• In the United States, the wind industry is thinly capitalized, except for the acquisition of Enron 

Wind Corporation by General Electric Co. About six manufacturers and six to 10 developers 

characterize the U.S. industry. 

• Enron Wind Corporation has been acquired by General Electric Corporation, Power Turbine 

Division. 

• In Europe, there are about 12 turbine manufacturers and about 20 to 30 project developers. 

European manufacturers have established North American manufacturing facilities and are actively 

participating in the U.S. market. 

• Current leading wind companies and sales volume are shown below:

U.S. Market (2003) World Market (2003)

MW Percent MW Percent

Vestas (DK) 347 20.9 1,812 21.7

GE Wind (USA) 874 52.6 1,503 18

Enercon (D) - - 1218 14.6

Gamesa (ESP) 55 3.3 956 11.5

NEG Micon (DK) 146 8.8 855 10.2

Bonus (DK) 15 0.9 552 6.6

Repower (D) - - 291 3.5

MADE (ESP) - - 243 2.9

Nordex (DK) - - 242 2.9

Mitsubishi (JP) 201 12.1 218 2.6

Others - - 441 5.3

Sources: U.S. Market: NREL estimate based on BTM Consult, ApS, “World Market Update 2003”, 

World Market: BTM Consult, ApS, “World Market Update 2003”

Technology History 

• Prior to 1980, DOE sponsored, and NASA managed, large-scale turbine development – starting 

with hundred-kilowatt machines and culminating in the late 1980s with the 3.2-MW, DOE-supported 

Mod-5 machine built by Boeing. 

• Small-scale (2-20 kW) turbine development efforts also were supported by DOE at the Rocky Flats 

test site. Numerous designs were available commercially for residential and farm uses. 

• In 1981, the first wind farms were installed in California by a small group of entrepreneurial 

companies. PURPA provided substantial regulatory support for this initial surge. 

• During the next five years, the market boomed, installing U.S., Danish, and Dutch turbines. 

• By 1985, annual market growth had peaked at 400 MW. Following that, federal tax credits were 

abruptly ended, and California incentives weakened the following year. 

• In 1988, European market exceeded the United States for the first time, spurred by ambitious 

national programs. A number of new companies emerged in the U.K. and Germany. 

• In 1989, DOE’s focus changed to supporting industry-driven research on components and systems. 

At the same time, many U.S. companies became proficient in operating the 1,600 MW of installed 

capacity in California. They launched into value engineering and incremental increases in turbine size. 

• DOE program supported value-engineering efforts and other advanced turbine-development efforts. 

• In 1992, Congress passed the Renewable Energy Production Tax Credit (REPI), which provided a 

1.5 cent/kWh tax credit for wind-produced electricity. Coupled with several state programs and 

mandates, installations in the United States began to increase. 

• In 1997, Enron purchased Zond Energy Systems, one of the value-engineered turbine 

manufacturers. In 2002, General Electric Co. purchased Enron Wind Corporation. 

• In FY2001, DOE initiated a low wind-speed turbine development program to broaden the U.S. 

cost-competitive resource base. 

38
Technology Future

The levelized cost of electricity for wind energy technology is projected to be: 

 2000 2002 20102020 

Class 4 6.0 5.5 3.0 2.7 

Class 6 4.2 4.0 2.4 2.2 

Assumptions include: 30-year levelized cost, constant January 2002 dollars, generation company 

ownership/financial assumptions; wind plant comprised of 100 turbines; no financial incentives 

included. 

Source: FY03 U.S. DOE Wind Program Internal Planning Documents, Summer 2001 

• Wind energy’s competitiveness by 2005 will be affected by policies regarding ancillary services 

and transmission and distribution regulations. Substantial cost reductions are expected for wind 

turbines designed to operate economically in low wind-speed sites, which will increase the amount of 

economical wind resource areas by 20-fold, and will be within 100 miles of most load centers. 

• Initial lower levels of wind deployment (up to 15–20% of the total U.S. electric system capacity) 

are not expected to introduce significant grid reliability issues. Inasmuch as the wind blows only 

intermittently, intensive use of this technology at larger penetrations may require modification to 

system operations or ancillary services. Transmission infrastructure upgrades and expansion will be 

required for large penetrations of wind energy to service major load centers. 

• Over the long term, as more high wind sites become used, emphasis will shift toward installation in 

lower wind-speed sites. Advances in technology will include various combinations of the following 

improvements, accomplished through continuing R&D: 

Towers – taller for more energy, softer to shed loads, advanced materials, and erection techniques 

to save cost. 

 Rotors – Improving airfoils and plan forms to increase energy capture. For instance, a variable rotor 

diameter; larger rotors at the same cost or small cost increase by optimizing design and manufacturing, 

using lighter materials, and implementing controls to mitigate loads. 

 Drive Train and Generators – New designs to reduce weight and cost. Advances in power 

electronics and operational algorithms to optimize drive-train efficiencies, especially by increasing low 

efficiencies in ranges of operation that are currently much lower than those in the peak range. In 

addition to new power electronics and operational approaches, possible advances include permanent 

magnet generators, and use of single-stage transmissions coupled with multiple smaller, simpler, offthe-shelf generators that can be purchased from high-volume manufacturers. 

 Controls – By reducing loads felt throughout the turbine, various approaches for passive and active 

control of turbines will enable larger, taller structures to be built for comparatively small cost increases, 

resulting in improvements in system cost of energy. 

 Design Codes – Reductions in design margins also will decrease the cost of turbines and allow for 

larger turbines to be built for comparatively small increases in cost, resulting in improvements in 

system cost of energy. 

 Foundations – New designs to lower cost. 

 Utility Grid Integration – Models and tools to analyze the steady and dynamic impact and 

operational characteristics of large wind farms on the electric grid will facilitate wind power 

integration. Improved wind forecasting and development of various enabling technologies will increase 

the value of wind power. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003

39
Wind 

Market Data 

Grid-Connected Wind Capacity (MW) 

Source: Reference IEA (data supplemented by Windpower Monthly, April 2001), 2001 data f

January 2002, 2002 data from AWEA "Global Wind Energy Market Report 2004".

Cumulative 1980 1985 1990 1995 1996 1997 1998 1999 2 U.S. 10 1,039 1,525 1,770 1,794 1,741 1,890 2,455 2, Germany 2 3 60 1,137 1,576 2,082 2,874 4,445 6, Spain 0 0 9 126 216 421 834 1,539 2, Denmark 3 50 310 630 785 1,100 1,400 1,752 2, Netherlands 0 0 49 255 305 325 364 416  Italy 3 22 70 103 180 282  UK 0 0 6 193 264 324 331 344  Europe 5 58 450 2,494 3,384 4,644 6,420 9,399 12, India 0 0 20 550 820 933 968 1,095 1, Japan 0 0 1 10 14 7 32 75  Rest of World 0 0 6 63 106 254 315 574  World Total 15 1,097 2,002 4,887 6,118 7,579 9,625 13,598 17,

 Installed U.S. Wind Capacity (MW) 

Source: Renewable Energy Project Information System (REPiS), Version 7, NREL, 2003.

1980 1985 1990 1995 1996 1997 1998 1999 200

 Annual 0.023 337 154 37 8 8 173 695 12 Cumulative1 0.060 674 1,569 1,773 1,781 1,788 1,961 2,656 2,781 There are an additional 48 MW of wind capacity that are not accounted for here because they have no specific online date. 2 2003 data not complete as REPiS database is updated through 2002. 

40
Annual Market Shares Source: US DOE- 1982-87 wind turbine shipment database; 1988-94. DOE Wind Prog

1996-2000 American Wind Energy Association

1980 1985 1990 1995 1996 1997 1998 1999 2000

 U.S. Mfg Share of U.S. Market 98% 44% 36% 67% NA 38% 78% 44% 0% U.S. Mfg Share of World Market 65% 42% 20% 5% 2% 4% 13% 9% 6%State-Installed Capacity Source: American Wind Energy Association. http://www.awea.org/projects/index.html Annual State-Installed Capacity (MW) Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 2000  California* N/A N/A 3 0 8.4 0.7 250 0  Texas 0 0 41 0 0 0 139.2 0  Minnesota 0 0 0 0 0.2 109.2 137.6 17.8  Iowa 0 0 0.1 0 1.2 3.1 237.5 0  Wyoming 0 0 0 0.1 0 1.2 71.3 18.1  Oregon 0 0 0 0 0 25.1 0 0  Washington 0 0 0 0 0 0 0 0  Colorado 0 0 0 0 0 0 21.6 0  New Mexico 0 0 0 0 0 0 1.3 0  Oklahoma 0 0 0 0 0 0 0 0  Total of 10 States N/A N/A 44 0 10 139 859 36 Total U.S. N/A N/A 44 1 16 142 884 67 Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 2000  California* N/A N/A 1,387 1,387 1,396 1,396 1,646 1,646  Texas 0 0 41 41 41 41 180.2 180.2 1 Minnesota 0 0 25.7 25.7 25.9 135.1 272.7 290.5  Iowa 0 0 0.7 0.8 2 5 242.5 242.5  Wyoming 0 0 0 0.1 0.1 1.3 72.5 90.6  Oregon 0 0 0 0 0 25.1 25.1 25.1  Washington 0 0 0 0 0 0 0 0  Colorado 0 0 0 0 0 0 21.6 21.6  New Mexico 0 0 0 0 0 0 1.3 1.3  Oklahoma 0 0 0 0 0 0 0 0  Total of 10 states N/A N/A 1,454 1,455 1,465 1,604 2,462 2,498 Total U.S. 10 1,039 1,525 1,697 1,698 1,706 1,848 2,511 2,578 

41
* The data set includes 1,193.53 MW of wind in California that is not given a specific installation year, but rather a range of ye

1981-1995, 87.98 in 1982-1987, and 33.19 MW in "mid-1980's"), this has led to the "Not Available" values for 1985 and 1990 totals, and this data is not listed in the annual installations, but has been added to the cumulative totals for 1995 and on. 

Cumulative Installed Capacity (MW) 

Source: U.S. - EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D

Table 8.11a; IEA R&D Wind Countries - IEA Wind Energy Annual Reports, 1995-2003. "Renewables Information 2002," IEA, 2002. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2

U.S. N/A 17.5 1,799 1,731 1,678 1,610 1,720 2,252 2,377 3IEA R&D Wind Countries2 10,040 15,440 21IEA Total 2,386 4,235 5,124 6,228 8,001 11,390 16,103 1. Wind capacity in 2002 will be revised upward to at least 4.4 million kilowatts, as the Energy Information Administration continues to identify new wind facilities. 2. Data for IEA R&D Wind Countries through 2001 included 16 IEA countries. Ireland and Switzerland were added in 2002 aPortugal was added in 2003. 

Annual Generation from Cumulative Installed Capacity (Billion kWh) 

Source: U.S. - EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., 8.2a; IEA R&D Wind Countries - IEA Wind Energy Annual Reports, 1995-2003. IEA Total - 

Information 2002", IEA, 2002. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. N/A 0.006 2.8 3.2 3.2 3.3 3.0 4.5 5.6 IEA R&D Wind Countries2 7.1 8.4 10.9 11.3 22.0 26.4 IEA Total 3.8 7.3 8.4 10.7 14.4 19.1 28.9 2. Data for International Energy Agency R&D Wind Countries through 2001 included 16 IEA countries. Ireland and Switzerla

and Portugal was added in 2003. 

Annual Wind Energy Consumption for Electric Generation (Trillion Btu) 

 Source: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., Septe

1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. Total N/A (s) 29.0 32.6 33.4 33.6 30.9 45.9 57.1 (s)=Less than 0.5 trillion Btu. 

42
Technology Performance 

Energy Production 

 Source: U.S.DOE Wind Program, 1980-1995, FY03 U.S.DOE Wind P

Planning Documents, Summer 2001, 2000-2020 

1980 1985 1990 1995 2000 2005 2

Capacity Factor (%) Class 4 10 15 20 25.2 32.6  Class 6 20 22 25 39.4 44.3 Specific Energy (kWh/m2*) Class 4 500 800 850 900 1,110 1 Class 6 900 1,150 1,300 1,400 1,650 1Production Efficiency** (kWh/kW) Class 4 200 650 1,300 1,750 2,200 2,860 3

 Class 6 800 1,700 1,900 2,200 3,450 3,880 4* m2 is the rotor swept area. ** Production Efficiency is the net energy per unit of installed capacity. Cost Source: FY03 U.S. DOE Wind Program Internal Planning Documents(Jan. 2002 dollars) 1980 1985 1990 1995 2000 2005 2

Project Cost ($/kW) Class 4 1,000 915 

 (Overnight costs) Class 6 1,000 900  O&M ($/kW) Class 4 11.0 7.9  Class 6 17.3 8.0  Fixed O&M & Land Class 4 8.0 8.0  ($/kW) Class 6 8.0 8.0 Specific Cost* (Project Capital Cost Per Rotor Captured Area - $/m2) 

Source: FY03 U.S. DOE Wind Program Internal Planning Documents

2000-2020. 

 (Jan. 2002 dollars) 1980 1985 1990 1995 2000 2005 2 Class 4 382 357  Class 6 414 340 Levelized Cost of Energy* ($/kWh) Source: U.S. DOE Wind Program 1980-1985; FY03 U.S. DOE Wind 

Planning Documents, Summer 2001, 2000-2020

 (Jan. 2002 dollars) 1980 1985 1990 1995 2000 2005 2 Class 4 0.12 0.080 0.060 0.041 0 Class 6 0.08 0.060 0.042 0.027 0* 30-year term. Generation Company Ownership/Financial Assumptions. Wind plant comprised of 100 turbines. No financial i

43
44
 Hydrogen

Technology Description 

Similar to electricity, hydrogen can be produced from many sources, including fossil fuels, renewable 

resources, and nuclear energy. Hydrogen and electricity can be converted from one to the other using 

electrolyzers (electricity to hydrogen) and fuel 

cells (hydrogen to electricity). Hydrogen is an 

effective energy storage medium, particularly 

for distributed generation. When hydrogen 

produced from renewable resources is used in 

fuel cell vehicles or power devices, there are 

very few emissions—the major byproduct is 

water. With improved conventional energy 

conversion and carbon-capture technologies, 

hydrogen from fossil resources can be used 

efficiently with few emissions. 

The Hydrogen Economy vision is based on a 

clean and elegant cycle: separate water into 

hydrogen and oxygen using renewable or 

nuclear energy, or fossil resources with carbon sequestration. Use the hydrogen to power a fuel cell, 

internal combustion engine, or turbine, where hydrogen and oxygen (from air) recombine to produce 

electrical energy, heat, and water to complete the cycle. This process produces no particulates, no 

carbon dioxide, and no pollution. 

System Concepts 

• Hydrogen made via electrolysis from excess nuclear or renewable energy can be used as a 

sustainable transportation fuel or stored to meet peak-power demand. It also can be used as a feedstock 

in chemical processes. 

• Hydrogen produced by decarbonization of fossil fuels followed by sequestration of the carbon can 

enable the continued, clean use of fossil fuels during the transition to a carbon-free Hydrogen 

Economy. 

• A hydrogen system is comprised of production, storage, distribution, and use. 

• A fuel cell works like a battery but does not run down or need recharging. It will produce electricity 

and heat as long as fuel (hydrogen) is supplied. A fuel cell consists of two electrodes—a negative 

electrode (or anode) and a positive electrode (or cathode)—sandwiched around an electrolyte. 

Hydrogen is fed to the anode, and oxygen is fed to the cathode. Activated by a catalyst, hydrogen 

atoms separate into protons and electrons, which take different paths to the cathode. The electrons go 

through an external circuit, creating a flow of electricity. The protons migrate through the electrolyte to 

the cathode, where they reunite with oxygen and the electrons to produce water and heat. Fuel cells can 

be used to power vehicles, or to provide electricity and heat to buildings. 

Representative Technologies 

Hydrogen production 

• Thermochemical conversion of fossil fuels, biomass, and wastes to produce hydrogen and CO2 with 

the CO2 available for sequestration (large-scale steam methane reforming is widely commercialized) 

• Renewable (wind, solar, geothermal, hydro) and nuclear electricity converted to hydrogen by 

electrolysis of water (commercially available electrolyzers supply a small but important part of the 

super-high-purity hydrogen market) 

• Photoelectrochemical and photobiological processes for direct production of hydrogen from 

sunlight and water. 

45
Hydrogen storage 

• Pressurized gas and cryogenic liquid (commercial today) 

• Higher pressure (10,000 psi), carbon-wrapped conformable gas cylinders 

• Cryogenic gas 

• Chemically bound as metal or chemical hydrides or physically adsorbed on carbon nanostructures 

Hydrogen distribution 

• By pipeline (relatively significant pipeline networks exist in industrial areas of the Gulf Coast 

region, and near Chicago) 

• By decentralized or point-of-use production using natural gas or electricity 

• By truck (liquid and compressed hydrogen delivery is practiced commercially) 

Hydrogen use 

• Transportation sector: internal combustion engines or fuel cells to power vehicles with electric 

power trains. Potential long-term use as an aviation fuel and in marine applications 

• Industrial sector: ammonia production, reductant in metal production, hydrotreating of crude oils, 

hydrogenation of oils in the food industry, reducing agent in electronics industry, etc. 

• Buildings sector: combined heat, power, and fuel applications using fuel cells 

• Power sector: fuel cells, gas turbines, generators for distributed power generation 

Technology Applications 

• In the United States, nearly all of the hydrogen used as a chemical (i.e. for petroleum refining and 

upgrading, ammonia production) is produced from natural gas. The current main use of hydrogen as a 

fuel is by NASA to propel rockets. 

• Hydrogen's potential use in fuel and energy applications includes powering vehicles, running 

turbines or fuel cells to produce electricity, and generating heat and electricity for buildings. The 

current focus is on hydrogen's use in fuel cells. 

The primary fuel cell technologies under development are: 

Phosphoric acid fuel cell (PAFC) - A phosphoric acid fuel cell (PAFC) consists of an anode and a 

cathode made of a finely dispersed platinum catalyst on carbon paper, and a silicon carbide matrix that 

holds the phosphoric acid electrolyte. This is the most commercially developed type of fuel cell and is 

being used in hotels, hospitals, and office buildings. More than 250 commercial units exist in 19 

countries on five continents. This fuel cell also can be used in large vehicles, such as buses. 

Proton-exchange membrane (PEM) - The proton-exchange membrane (PEM) fuel cell uses a 

fluorocarbon ion exchange with a polymeric membrane as the electrolyte. The PEM cell appears to be 

more adaptable to automobile use than the PAFC type of cell. These cells operate at relatively low 

temperatures and can vary their output to meet shifting power demands. These cells are the best 

candidates for light-duty vehicles, for buildings, and much smaller applications. 

Solid oxide fuel cells (SOFC) - Solid oxide fuel cells (SOFC) currently under development use a thin 

layer of zirconium oxide as a solid ceramic electrolyte, and include a lanthanum manganate cathode 

and a nickel-zirconia anode. This is a promising option for high-powered applications, such as 

industrial uses or central electricity generating stations. 

Direct-methanol fuel cell (DMFC) - A relatively new member of the fuel cell family, the directmethanol fuel cell (DMFC) is similar to the PEM cell in that it uses a polymer membrane as an 

electrolyte. However, a catalyst on the DMFC anode draws hydrogen from liquid methanol, eliminating 

the need for a fuel reformer. 

Molten carbonate fuel cell (MCFC) - The molten carbonate fuel cell uses a molten carbonate salt as the 

electrolyte. It has the potential to be fueled with coal-derived fuel gases or natural gas. 

Alkaline fuel cell - The alkaline fuel cell uses an alkaline electrolyte such as potassium hydroxide. 

Originally used by NASA on missions, it is now finding applications in hydrogen-powered vehicles. 

Regenerative or Reversible Fuel Cells - This special class of fuel cells produces electricity from 

hydrogen and oxygen, but can be reversed and powered with electricity to produce hydrogen and 

oxygen. 

46
Current Status 

• Currently, 48% of the worldwide production of hydrogen is via large-scale steam reforming of 

natural gas. Today, we safely use about 90 billion cubic meters (3.2 trillion cubic feet) of hydrogen 

yearly. 

• Direct conversion of sunlight to hydrogen using a semiconductor-based photoelectrochemical cell 

was recently demonstrated at 12.4% efficiency. 

• Hydrogen technologies are in various stages of development across the system: 

Production - Hydrogen production from conventional fossil-fuel feedstocks is commercial, and results 

in significant CO2 emissions. Large-scale CO2 sequestration options have not been proved and require 

R&D. Current commercial electrolyzers are 70-80% efficient, but the cost of hydrogen is strongly 

dependent on the cost of electricity. Production processes using wastes and biomass are under 

development, with a number of engineering scale-up projects underway. 

Storage - Liquid and compressed gas tanks are available and have been demonstrated in a small 

number of bus and automobile demonstration projects. Lightweight, fiber-wrapped tanks have been 

developed and tested for higher-pressure hydrogen storage. Experimental metal hydride tanks have 

been used in automobile demonstrations. Alternative solid-state storage systems using alanates and 

carbon nanotubes are under development. 

Use - Small demonstrations by domestic and foreign auto and bus companies have been undertaken. 

Small-scale power systems using fuel cells are being beta-tested. Small fuel cells for battery 

replacement applications have been developed. Much work remains. 

• There have been important advances in storage energy densities in recent years: High-pressure 

composite tanks have been demonstrated with 7.5 wt.% storage capacity, exceeding the current DOE 

target, and new chemical hydrides have demonstrated a reversible capacity of 5 wt.% hydrogen. The 

composite tank development is a successful technology partnership among the national labs, DOE, and 

industry. Industrial investment in chemical hydride development recently has been initiated. 

• SunLine Transit receives support to operate a variety of hydrogen production processes for its bus 

fleet. The California Fuel Cell Partnership has installed hydrogen refueling equipment (liquid delivered 

to the facility) 

• Major industrial companies are pursuing R&D in fuel cells and hydrogen reformation technologies 

with a mid-term time frame for deployment of these technologies for both stationary and vehicular 

applications. These companies include: 

 ExxonMobil Toyota 

Shell Daimler-Chrysler 

Texaco Honda 

BP International Fuel Cells 

General Motors Ballard 

Ford Air Products 

Daimler-Chrysler Praxair 

Toyota Plug Power Systems 

Technology History 

• From the early 1800s to the mid-1900s, a gaseous product called town gas (manufactured from 

coal) supplied lighting and heating for America and Europe. Town gas is 50% hydrogen, with the rest 

comprised of mostly methane and carbon dioxide, with 3% to 6% carbon monoxide. Then, large natural 

gas fields were discovered, and networks of natural gas pipelines displaced town gas. (Town gas is still 

found in limited use today in Europe and Asia.) 

• From 1958 to present, the National Aeronautics and Space Administration (NASA) has continued 

work on using hydrogen as a rocket fuel and electricity source via fuel cells. NASA became the 

worldwide largest user of liquid hydrogen and is renowned for its safe handling of hydrogen. 

• During the 20th century, hydrogen was used extensively as a key component in the manufacture of 

47
ammonia, methanol, gasoline, and heating oil. It was—and still is—also used to make fertilizers, glass, 

refined metals, vitamins, cosmetics, semiconductor circuits, soaps, lubricants, cleaners, margarine, and 

peanut butter. 

• Recently, (in the late 20th century/dawn of 21st century) many industries worldwide have begun 

producing hydrogen, hydrogen-powered vehicles, hydrogen fuel cells, and other hydrogen products. 

From Japan’s hydrogen delivery trucks to BMW’s liquid-hydrogen passenger cars; to Ballard’s fuel 

cell transit buses in Chicago and Vancouver, B.C.; to Palm Desert’s Renewable Transportation Project; 

to Iceland’s commitment to be the first hydrogen economy by 2030; to the forward-thinking work of 

many hydrogen organizations worldwide; to Hydrogen Now!’s public education work; the dynamic 

progress in Germany, Europe, Japan, Canada, the United States, Australia, Iceland, and several other 

countries launch hydrogen onto the main stage of the world’s energy scene. Specific U.S.-based 

examples of hydrogen production and uses are as follows: 

- A fully functional integrated renewable hydrogen utility system for the generation of hydrogen using 

concentrated solar power was demonstrated by cooperative project between industry and an Arizona 

utility company. 

- A renewable energy fuel cell system in Reno, Nevada, produced hydrogen via electrolysis using 

intermittent renewable resources such as wind and solar energy. 

- An industry-led project has developed fueling systems for small fleets and home refueling of 

passenger vehicles. The refueling systems deliver gaseous hydrogen up to 5,000 psi to the vehicle. 

A transit agency in California installed an autothermal reformer, generating hydrogen for buses and 

other vehicles. This facility also operates a PV-powered electrolysis system to provide renewable 

hydrogen to their fleet. 

Technology Future 

• Fuel cells are a promising technology for use as a source of heat and electricity for buildings, and 

as an electrical power source for electric vehicles. Although these applications would ideally run off 

pure hydrogen, in the near-term they are likely to be fueled with natural gas, methanol, or even 

gasoline. Reforming these fuels to create hydrogen will allow the use of much of our current energy 

infrastructure—gas stations, natural gas pipelines, etc.—while fuel cells are phased in. The electricity 

grid and the natural gas pipeline system will serve to supply primary energy to hydrogen producers. 

• By 2005, if DOE R&D goals are met, (1) onboard hydrogen storage in metal hydrides at >5 wt% 

will be developed; (2) complete engineering design of a small-scale, mass-producible reformer for 

natural gas will be completed; and (3) an integrated biomass-to-hydrogen system will be demonstrated. 

• By 2010, advances will be made in photobiological and photoelectrochemical processes for 

hydrogen production, efficiencies of fuel cells for electric power generation will increase, and advances 

will be made in fuel cell systems based on carbon structures, alanates, and metal hydrides. The RD&D 

target for 2010 is $45/kW for internal combustion engines operating on hydrogen; the cost goal is 

$30/kW by 2015. 

• Although comparatively little hydrogen is currently used as fuel or as an energy carrier, the longterm potential is for us to make a transition to a hydrogen-based economy in which hydrogen will join 

electricity as a major energy carrier. Furthermore, much of the hydrogen will be derived from 

domestically plentiful renewable energy or fossil resources, making the Hydrogen Economy 

synonymous with sustainable development and energy security. 

• In summary, future fuel cell technology will be characterized by reduced costs and increased 

reliability for transportation and stationary (power) applications. 

• To enable the transition to a hydrogen economy, the cost of hydrogen energy is targeted to be 

equivalent to gasoline market prices ($1.50/gallon in 2001 dollars). 

• For a fully developed hydrogen energy system, a new hydrogen infrastructure/delivery system will 

be required. 

48
• In the future, hydrogen also could join electricity as an important energy carrier. An energy carrier 

stores, moves, and delivers energy in a usable form to consumers. Renewable energy sources, such as 

the sun or wind, can't produce energy all the time. The sun doesn't always shine nor the wind blow. But 

hydrogen can store this energy until it is needed and it can be transported to where it is needed. 

• Some experts think that hydrogen will form the basic energy infrastructure that will power future 

societies, replacing today's natural gas, oil, coal, and electricity infrastructures. They see a new 

hydrogen economy to replace our current energy economies, although that vision probably won't 

happen until far in the future. 

Sources: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003; and National 

Renewable Energy Laboratory. Gas-Fired Distributed Energy Resource Technology Characterizations. 

NREL/TP-620/34783. November 2003. 

49
50
Advanced Hydropower

Technology Description 

Advanced hydropower is new 

technology for producing 

hydroelectricity more efficiently, with 

improved environmental performance. 

Current technology often has adverse 

environmental effects, such as fish 

mortality and changes to downstream 

water quality and quantity. The goal of 

advanced hydropower technology is to 

maximize the use of water for 

hydroelectric generation while 

eliminating these adverse side 

effects—in many cases both increased 

energy and improved environmental 

conditions can be achieved. 

System Concepts

• Conventional hydropower projects use either impulse or reaction turbines to convert kinetic energy 

in flowing or falling water into turbine torque and power. Source water may be from free-flowing 

rivers/streams/canals or released from upstream storage reservoirs. 

• Improvements and efficiency measures can be made in dam structures, turbines, generators, 

substations, transmission lines, and systems operation that will help sustain hydropower’s role as a 

clean, renewable energy source. 

Representative Technologies 

• Turbine designs that minimize entrainment mortality of fish during passage through the power 

plant. 

• Autoventing turbines to increase dissolved oxygen in discharges downstream of dams. 

• Reregulating and aerating weirs used to stabilize tailwater discharges and improve water quality. 

• Adjustable-speed generators producing hydroelectricity over a wider range of heads and providing 

more uniform instream flow releases without sacrificing generation opportunities. 

• New assessment methods to balance instream flow needs of fish with water for energy production. 

• Advanced instrumentation and control systems that modify turbine operation to maximize 

environmental benefits and energy production. 

Technology Applications 

• Advanced hydropower products can be applied at more than 80% of existing hydropower projects 

(installed conventional capacity is now 78 GW); the potential market also includes 15–20 GW at 

existing dams without hydropower facilities (i.e., no new dams required for development) and about 30 

GW at undeveloped sites that have been identified as suitable for new dams. 

• The nation's largest hydropower plant is the 7,600 megawatt Grand Coulee power station on the 

Columbia River in Washington State. The plant is being upscaled to 10,080 megawatts, which will 

make it the third largest in the world. 

• There would be significant environmental benefits from installing advanced hydropower 

technology, including enhancement of fish stocks, tailwater ecosystems, and recreational opportunities. 

These benefits would occur because the advanced technology reverses adverse effects of the past. 

• Additional benefits would come from the protection of a wide range of ancillary benefits that are 

provided at hydropower projects but are at extreme risk of becoming lost in the new deregulated 

environment. 

51
Current Status 

• Hydropower (also called hydroelectric power) facilities in the United States can generate enough 

power to supply 28 million households with electricity, the equivalent of nearly 500 million barrels of 

oil. The total U.S. hydropower capacity—including pumped storage facilities—is about 95,000 

megawatts. Researchers are working on advanced turbine technologies that will not only help 

maximize the use of hydropower but also minimize adverse environmental effects. 

• According to EIA, hydropower provided 12.6% of the nation’s electricity generating capability in 

1999 and 80% of the electricity produced from renewable energy sources. 

• DOE estimates current capital costs for large hydropower plants to be $1,700 to $2,300 per kW 

(although no new plants are currently being built in the United States and O&M is estimated at 

approximately 0.7 cents/kWh). 

• Worldwide, hydropower plants have a combined capacity of 675,000 megawatts and annually 

produce more than 2.3 trillion kilowatt-hours of electricity, the energy equivalent of 3.6 billion barrels 

of oil. 

• Existing hydropower generation is declining because of a combination of real and perceived 

environmental problems, regulatory pressures, and changes in energy economics (deregulation, etc.); 

potential hydropower resources are not being developed for similar reasons. 

• The current trend is to replace hydropower with electricity from fossil fuels. 

• Some new, environmentally friendly technologies are being implemented (e.g., National 

Hydropower Association’s awards for Outstanding Stewardship of America’s Rivers). 

• DOE's Advanced Hydropower Turbine System (AHTS) program constructed a test facility to pilot 

test a new turbine design to evaluate hydraulic and biological performance; testing at this facility was 

completed in 2003. This program is demonstrating that new turbine designs are feasible, but additional 

support is needed to fully evaluate these new designs in full-scale applications. 

• There is insufficient understanding of how fish respond to turbulent flows in draft tubes and 

tailraces to support biological design criteria for those zones of power plants. 

• Fish resource management agencies do not recognize that the route through turbines is acceptable 

for fish—this perception could be overcome if field-testing continues to show mortality through 

turbines is not greater than other passage routes. 

• TVA’s Lake Improvement Plan has demonstrated that improved turbine designs can be 

implemented with significant economic and environmental benefits. This effort has shown increases in 

hydroelectric plants’ energy production by 12% with significantly improvements of downstream fish 

resources. 

• Field-testing of the Minimum Gap Runner (MGR) designs for Kaplan turbines indicate that fish 

survival up to 98% is possible, if conventional turbines are modified. 

• FERC instituted a short-term reduction in regulatory barriers on the West Coast in 2001—this 

resulted in more than 100,000 MWh of additional generation and a significant shift from nonpeak to 

peak production, without significant adverse environmental effects. 

• Regulatory trends in relicensing are to shift operation from peaking to baseload, effectively 

reducing the energy value of hydroelectricity; higher instream flow requirements are also reducing total 

energy production to protect downstream ecosystems, but scientific justification is weak. 

• Frequent calls for dam removal is making relicensing more costly to dam owners. 

• Regional efforts by Army Corps of Engineers and Bonneville Power Administration are producing 

some site-specific new understanding, especially in the Columbia River basin; but commercial 

applications are unlikely because of pressures from industry deregulation and environmental regulation.

• Voith-Siemans Hydro and TVA have established a limited partnership to market environmentally 

friendly technology at hydropower facilities. Their products were developed in part by funding 

provided by DOE and the Corps of Engineers, as well as private sources. 

• Flash Technology is developing strobe lighting systems to force fish away from hydropower 

intakes and to avoid entrainment mortality in turbines. 

52
Technology History 

• Since the time of ancient Egypt, people have used the energy in flowing water to operate machinery 

and grind grain and corn. However, hydropower had a greater influence on people's lives during the 

20th century than at any other time in history. Hydropower played a major role in making the wonders 

of electricity a part of everyday life and helped spur industrial development. Hydropower continues to 

produce 24% of the world's electricity and supply more than 1 billion people with power. 

• The first hydroelectric power plant was built in 1882 in Appleton, Wisconsin, to provide 12.5 

kilowatts to light two paper mills and a home. Today's hydropower plants generally range in size from 

several hundred kilowatts to several hundred megawatts, but a few mammoth plants have capacities up 

to 10,000 megawatts and supply electricity to millions of people. 

• By 1920, 25% of electrical generation in the United States was from hydropower; and, by 1940, 

was 40%. 

• Most hydropower plants are built through federal or local agencies as part of a multipurpose 

project. In addition to generating electricity, dams and reservoirs provide flood control, water supply, 

irrigation, transportation, recreation, and refuges for fish and birds. Private utilities also build 

hydropower plants, although not as many as government agencies. 

Technology Future 

• By 2003, a quantitative understanding of the responses of fish to multiple stresses inside a turbine 

should be developed. Biological performance criteria for use in advanced turbine design also should be 

available. 

• By 2005, environmental mitigation studies should be available on topics such as in-stream flow 

needs to produce more efficient and less controversial regulatory compliance. In addition, pilot-scale 

testing of new runner designs, including field evaluation of environmental performance, will allow fullscale prototype construction and testing to proceed. 

• By 2010, full-scale prototype testing of AHTS designs should be completed, including verified 

biological performance of AHTS in the field. This will allow AHTS technology to be transferred to the 

market. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

53
Hydroelectric Power 

Market Data U.S. Installed Capacity (MW)* Source: Renewable Energy Project Information System (REPiS), Version 7, NREL, 2003

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Annual 1,391 3,237 862 1,054 19.9 64.0 7.6 179.3 1.1 Cumulative 80,491 87,839 90,955 94,052 94,072 94,136 94,143 94,323 94,324 * There are an additional 21 MW of hydroelectric capacity that are not accounted for here because they have no specific on

2003 data not complete as REPiS database is updated through 2002. 

Cumulative GridConnected Hydro Capacity (MW)1

Source: U.S. data from EIA, AER 2003 Table 8.11a, World Total from EIA, International Energy Ann

International data from International Energy Agency, Electricity Information 2004. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. 

Conventional and other Hydro 81,700 88,900 73,923 78,562 76,437 79,415 79,151 79,393 79,359 7Pumped Storage2 N/A N/A 19,462 21,387 21,110 19,310 19,518 19,565 19,522 1

U.S. Hydro Total 81,700 88,900 93,385 99,948 97,548 98,725 98,669 98,958 98,881 9OECD Europe3 124,184 124,577 130,886 132,893 134,902 135,939 133,307 136,251 140,779 14

IEA Europe4 123,960 124,357 130,663 132,666 134,038 135,074 132,315 135,254 138,093 13

Japan 21,377 19,980 20,825 21,171 21,222 21,277 21,477 21,555 22,019 2

OECD Total 286,969 300,725 316,291 340,259 342,893 346,342 342,673 346,446 351,513 35

IEA Total 286,745 300,505 316,068 330,703 331,947 335,395 331,930 335,768 339,145 33

World Total 470,669 537,734 600,206 650,936 661,237 673,797 680,610 697,749 712,689 72

1. Excludes pumped storage, except for specific U.S. pumped storage capacity listed. 2. Pumped storage values for 1980-1985 are included in "Conventional and other Hydro" 3. OECD included 24 countries as of 1980. Mexico, Czech Republic, Hungary, Poland, South Korea, Slovak Republic joined a

are included only after the year they joined. 

54
4. IEA included 26 countries as of 2003. Countries' data are included only after the year they joined the OECD. 

NA = Not Available; Updated international data not available at time of publication 

Annual Generation from Cumulative Installed Capacity (Billion kWh) 

 Source: EIA, International Energy Annual 2002, DOE/EIA-0219(02), Table 1.5. 

1980 1985 1990 1995 1996 1997 1998 1999 200

United States 279 284 289 308 344 352 319 313 27Canada 251 301 294 332 352 347 329 342 35Mexico 17 26 23 27 31 26 24 32 3Brazil 128 177 205 251 263 276 289 290 30Western Europe 432 453 453 506 491 506 523 531 55Former U.S.S.R. 184 205 231 238 215 216 225 227 22Eastern Europe 27 26 23 34 34 36 35 35 3China 58 91 125 184 185 193 203 211 24Japan 88 82 88 81 80 89 92 86 8Rest of World 273 328 435 504 515 522 533 541 55World Total 1,736 1,973 2,167 2,466 2,511 2,564 2,571 2,609 2,65State Generating Capability* (MW) 

Source: EIA, Electric Power Annual 2002 – Spreadsheets, “1990 - 2002 Existing Namepla

Capacity by Energy Source and Producer Type (EIA-860)” 

http://www.eia.doe.gov/cneaf/electricity/epa/existing_capacity_state.xls 

Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 20Washington 19,935 20,487 20,431 20,923 21,012 21,011 21,0California 12,687 13,519 13,500 13,475 13,383 13,445 13,4Oregon 8,221 8,268 8,267 8,264 8,265 8,249 8,2New York 5,345 5,545 5,557 5,565 5,668 5,662 5,6Tennessee 3,717 3,818 3,818 3,937 3,950 3,950 3,9Georgia 2,453 3,287 3,005 3,305 3,314 3,314 3,3South Carolina 2,367 3,468 3,468 3,442 3,442 3,452 3,4Virginia 3,072 3,126 3,149 3,082 3,093 3,090 3,0

55
Alabama 2,857 2,868 2,864 2,904 2,961 2,961 2,9

Arizona 2,685 2,885 2,885 2,893 2,893 2,890 2,8U.S. Total 89,828 94,513 94,372 95,222 95,496 95,802 95,8* Values are nameplate capacity for total electric industry 

State Annual Generation from Cumulative Installed Capacity* (Billion kWh) 

Source: EIA, Electric Power Annual 2002 – Spreadsheets, “1990 - 2002 Net Generation b

Producer by Energy Source (EIA-906)” http://www.eia.doe.gov/cneaf/electricity/epa/gene

Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 20Washington 87.5 82.5 98.5 104.2 79.8 97.0 8Oregon 41.2 40.8 44.9 46.7 39.9 45.6 3California 24.8 50.5 46.9 42.1 50.8 40.4 3New York 27.1 24.8 27.8 29.5 28.2 23.6 2Montana 10.7 10.7 13.8 13.4 11.1 13.8 Alabama 10.4 9.5 11.1 11.5 10.6 7.8 Idaho 9.1 11.0 13.3 14.7 12.9 13.5 1Arizona 7.7 8.5 9.5 12.4 11.2 10.1 Tennessee 9.5 9.0 10.8 10.4 10.2 7.2 South Dakota 3.9 6.0 8.0 9.0 5.8 6.7 U.S. Total 289.4 308.1 344.1 352.4 318.9 313.4 27* Values are for total electric industry. Years before 1998 do not include nonutility generation. 

Annual Hydroelectric Consumption for Electric Generation (Trillion Btu) 

Source: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., Septemb

8.4a

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. Total 2,900 2,970 3,046 3,205 3,590 3,640 3,297 3,268 2,811 2,201 Note: Conventional hydroelectric power only, for all sectors. Hydroelectric data through 1988 include industrial plants as well as electric utilities. Beginning in 1989, data are for electriutilities, independent power producers, commercial plants, and industrial plants. 

56
Solar Buildings

Technology Description 

Solar building technologies deliver heat, electricity, light, hot water, and cooling to residential and 

commercial buildings. By combining solar thermal and electric building technologies with very energyefficient construction methods, lighting, and appliances, it is possible to build “Zero Energy Homes” 

(see photo for a demonstration-home example). Zero Energy Buildings (residential and commercial) 

have a zero net need for off-site energy on an annual basis and also have no carbon emissions. 

System Concepts 

• In solar heating systems, solar-thermal 

collectors convert solar energy into heat at the 

point of use, usually for domestic hot water and 

space heating. 

• In solar cooling systems, solar-thermal 

collectors convert solar energy into heat for 

absorption chillers or desiccant regeneration. 

• In solar lighting systems, sunlight is 

transmitted into the interior of buildings using 

glazed apertures, light pipes, and/or optical 

fibers. 

Representative Technologies 

• Active solar-heating systems use pumps and controls to circulate a heat transfer fluid between the 

solar collector(s) and storage. System sizes can range from 1 to 100 kW. 

• Passive solar-heating systems do not use pumps and controls but rather rely on natural circulation 

to transfer heat into storage. System sizes can range from 1 to 10 kW. 

• Transpired solar collectors heat ventilation air for industrial and commercial building applications. 

A transpired collector is a thin sheet of perforated metal that absorbs solar radiation and heats fresh air 

drawn through its perforations. 

• Hybrid solar lighting systems focus concentrated sunlight on optical fibers in order to combine 

natural daylight with conventional illumination. Hybrid Solar Lighting (HSL) has the potential to more 

than double the efficiency and affordability of solar energy in commercial buildings by simultaneously 

separating and using different portions of the solar-energy spectrum for different end-use purposes, i.e. 

lighting and distributed power generation. 

Technology Applications 

• More than 1,000 MW of solar water-heating systems are operating successfully in the United 

States, generating more than 3 million MW-hrs per year. 

• Based on peer-reviewed market penetration estimates, there will be approximately 1 million new 

solar water-heating systems installed by 2020, offering an energy savings of 0.16 quads (164 trillion 

Btus). 

• Retrofit markets: There are 73 million existing single-family homes in the United States. An estimate 

of the potential replacement market of 29 million solar water-heating systems assumes that only 40% 

of these existing homes have suitable orientation and nonshading. (9.2 million replacement electric and 

gas water heaters.) 

• New construction: In 2000, 1.2 million new single-family homes were built in the United States. 

Assuming 70% of these new homes could be sited to enable proper orientation of solar water-heating 

systems, this presents another 840,000 possible system installations annually. 

• While the ultimate market for the zero-energy building concept is all new building construction; the 

near-term focus is on residential buildings; particularly, single-family homes in the Sunbelt areas of the 

57
country. Of the 1.2 million new single-family homes built in the United States in 2000, 44% of these 

new homes were in the southern region of the country and 25% were in the western region, both areas 

with favorable solar resources. 

Current Status 

• About 1.2 million solar water-heating systems have been installed in the United States, mostly in 

the 1970s and 1980s. Due to relatively low energy prices and other factors, there are approximately 

only 8,000 installations per year. 

• Typical residential solar systems use glazed flat-plate collectors combined with storage tanks to 

provide 40% to 70% of residential water-heating requirements. Typical systems generate 2500 kWh of 

energy per year and cost $1 to $2/Watt, or 8¢/kWh. 

• The energy costs of solar thermal systems have declined by more than 50% due to technology 

improvements. This cost reduction has saved more than five million MWh/year in U.S. primary energy 

consumption. 

• Typical solar pool-heating systems use unglazed polymer collectors to provide 50% to 100% of 

residential pool-heating requirements. Typical systems generate 1,600 therms or 46,000 kWh of energy 

per year and cost $0.30 to $0.50/Watt 

• Four multidisciplinary homebuilding teams have begun the initial phase of designing and 

constructing “Zero Energy Homes” for various new construction markets in the United States. Several 

homebuilders have started building houses with Zero Energy Home features—solar electric systems, 

solar water heating, and energy-efficient construction. 

• Key companies developing or selling solar water heaters include: 

 

Alternative Energy Technologies Harter Industries 

Aquatherm Duke Solar 

FAFCO Heliodyne, Inc. 

Radco Products Sun Earth 

Sun Systems Thermal Conversion Technologies 

Technology History 

• 1890s- First commercially available solar water heaters produced in southern California. Initial 

designs were roof-mounted tanks and later glazed tubular solar collectors in thermosiphon 

configuration. Several thousand systems were sold to homeowners. 

• 1900s- Solar water-heating technology advanced to roughly its present design in 1908 when 

William J. Bailey of the Carnegie Steel Company, invented a collector with an insulated box and 

copper coils. 

• 1940s- Bailey sold 4,000 units by the end of WWI, and a Florida businessperson who bought the 

patent rights sold nearly 60,000 units by 1941. 

• 1950s- Industry virtually expires due to inability to compete against cheap and available natural gas 

and electric service. 

• 1970s- The modern solar industry began in response to the OPEC oil embargo in 1973-74, with a 

number of federal and state incentives established to promote solar energy. President Jimmy Carter put 

solar water-heating panels on the White House. FAFCO, a California company specializing in solar 

pool heating; and Solaron, a Colorado company that specialized in solar space and water heating, 

became the first national solar manufacturers in the United States. In 1974, more than 20 companies 

started production of flat-plate solar collectors, most using active systems with antifreeze capabilities. 

Sales in 1979 were estimated at 50,000 systems. In Israel, Japan, and Australia, commercial markets 

and manufacturing had developed with fairly widespread use. 

• 1980s- In 1980, the Solar Rating and Certification Corp (SRCC) was established for testing and 

certification of solar equipment to meet set standards. In 1984, the year before solar tax credits expired, 

58
an estimated 100,000-plus solar hot-water systems were sold. Incentives from the 1970s helped create 

the 150-business manufacturing industry for solar systems with more than $800 million in annual sales 

by 1985. When the tax credits expired in 1985, the industry declined significantly. During the Gulf 

War, sales again increased by about 10% to 20% to its peak level, more than 11,000 square feet per 

year (sq.ft./yr) in 1989 and 1990. 

• 1990s- Solar water-heating collector manufacturing activity declined slightly, but has hovered 

around 6,000 to 8,000 sq.ft./yr. Today's industry represents the few strong survivors: More than 1.2 

million buildings in the United States have solar water-heating systems, and 250,000 solar-heated 

swimming pools exist. Unglazed, low-temperature solar water heaters for swimming pools have been a 

real success story, with more than a doubling of growth in square footage of collectors shipped from 

1995 to 2001. 

Reference: American Solar Energy Society and Solar Energy Industry Association 

Technology Future 

• Near-term solar heating and cooling RD&D goals are to reduce the costs of solar water-heating 

systems to 4¢/kWh from their current cost of 8¢/kWh using polymer materials and manufacturing 

enhancements. This corresponds to a 50% reduction in capital cost. 

• Near-term Zero Energy Building RD&D goals are to reduce the annual energy bill for an averagesize home by 50% to $600 by 2004 and to $0 by 2020. 

• Near-term solar lighting RD&D goals are to reduce the costs of solar lighting systems to 5¢/kWh. 

• Zero-energy building RD&D efforts are targeted to optimize various energy efficiency and 

renewable energy combinations, integrate solar technologies into building materials and the building 

envelope, and incorporate solar technologies into building codes and standards. 

• Solar heating and cooling RD&D efforts are targeted to reduce manufacturing and installation 

costs, improve durability and lifetime, and provide advanced designs for system integration. 

The RD&D goal by 2025 is to research, develop, and demonstrate marketable and advanced energy 

systems needed to achieve “net-zero” energy use in new residential and commercial buildings. To 

achieve this, a 70% reduction in building energy use is needed; this can be achieved through highperformance lighting, HVAC, and appliances. The balance of the energy requirements will be met by 

renewable energy sources. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003. 

59
Solar Buildings 

Market Data 

U.S. Installations (Thousands of Sq. Ft.) 

Source: EIA, Renewable Energy Annual 2003 Table 18 and Table 10, REA 2002 Table 18, REA 

1997- 2000 Table 16, REA 1996 Table 18 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Annual 

DHW 755 765 595 463 373 367 

Pool Heaters 6,763 6,787 7,528 7,201 8,141 7,863 

Total Solar Thermal 1 18,283 19,166 11,164 7,136 7,162 7,759 7,396 8,046 7,857 

Cumulative DHW Pool Heaters Total Solar Thermal 1 62,829 153,035 199,459 233,386 240,548 248,307 255,703 263,749 271,606 

1. Domestic shipments - total shipments minus export shipments U.S. Annual Shipments (Thousand Sq. Ft.) 

Source: EIA, Renewable Energy Annual 2003 Table 11 and REA 1999 Table 11. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Total 19,398 N/A 11,409 7,666 7,616 8,138 7,756 8,583 8,354 

Imports N/A 1,562 2,037 1,930 2,102 2,206 2,352 2,201 

Exports 1,115 N/A 245 530 454 379 360 537 496 

U.S. Shipments by Cell Type (thousands of sq. ft.) 

Source: EIA Annual Energy Review 2003 Table 10.3 and Renewable E

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Low-Temperature Collectors 

12,233 N/A 3,645 6,813 6,821 7,524 7,292 8,152 7,948 

Medium-Temperature Collectors 

7,165 N/A 2,527 840 785 606 443 427 400 

60
High-Temperature 

Collectors 

N/A N/A 5,237 13 10 7 21 4 5 

Total 19,398 N/A 11,409 7,666 7,616 8,137 7,756 8,583 8,353 

1985 values not available. 

U.S. Shipments of High Temperature Collectors by Market Sector, and End Use (Thousands of Sq. Ft.) 

Source: EIA, Renewable Energy Annual 2003 Table 18, REA 2002 Table 18, REA 19

1999-2000 Table 16, and REA 1998 Table 19. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Market Sector  Residential 0 0 0 0 0  Commercial 1 7 7 18 0  Industrial 0 2 0 0 0  Utility 9 0 0 2 4  Other 3 0 0 1 0 Total 13 10 7 21 4 End Use  Pool Heating 0 0 0 0 0  Hot Water 0 7 7 18 0  Space Heating 0 0 0 0 0  Space Cooling 1 0 0 0 0  Combined Space and Water Heating 0 0 0 0 0  Process Heating 0 2 0 0 0  Electricity Generation 9 0 0 2 4  Other 2 0 0 1 0 Total 13 10 7 21 4 2000 data not published by EIA 

61
U.S. Shipments of MediumTemperature Collectors by Market 

Sector, and End Use (Thousands of Sq. Ft.) 

Source: EIA, Renewable Energy Annual 2003 Table 18, REA 2002 Table 18, REA 19

1999-2000 Table 16, and REA 1998 Table 19. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Market Sector  Residential 774 728 569 355 366  Commercial 51 50 35 70 59  Industrial 12 1 0 18 0  Utility 0 0 0 0 0  Other 3 7 2 0 2 Total 839 786 606 443 426 End Use  Pool Heating 32 21 11 36 12  Hot Water 743 754 588 384 373  Space Heating 62 6 2 13 24  Space Cooling 0 0 0 0 0  Combined Space and Water Heating 2 2 3 8 16  Process Heating 0 1 0 0 0  Electricity Generation 0 0 0 0 0  Other 0 0 1 1 2 Total 839 784 605 442 427 2000 data not published by EIA 

U.S. Shipments of Low- Temperature Collectors by Market Sector, and End Use (Thousands of Sq. Ft.) 

Source: EIA, Renewable Energy Annual 2003 Table 18, REA 2002 Table 18, REA 191999-2000 Table 16, and REA 1998 Table 19. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

Market Sector  Residential 6,192 6,146 6,791 6,810 7,408 

62
 Commercial 552 625 726 429 726 

 Industrial 69 51 7 44 18  Utility 0 0 0 0 0  Other 0 0 0 2 0 Total 6,813 6,822 7,524 7,285 8,152 End Use  Pool Heating 6,731 6,766 7,517 7,164 8,129  Hot Water 11 4 0 60 0  Space Heating 70 51 7 53 18  Space Cooling 0 0 0 0 0  Combined Space and Water Heating * 0 0 8 0  Process Heating 0 0 0 0 5  Electricity Generation 0 0 0 0 0  Other 0 0 0 0 0 Total 6,813 6,821 7,524 7,285 8,152 2000 data not published by EIA 

63
Technology Performance 

Energy Production 

 Source: Arthur D. Little, Review of FY 2001 Office of Power Technology's Solar Building

Summary, December 1999.

1980 1985 1990 1995 2000 2005 2010 

Energy Savings  DHW (kWh/yr) 2,750  Pool Heater (therms/yr) 1,600 

Cost 

Source: Hot-Water Heater data from Arthur D. Little, Water-Heating Situation Analysis, N

and Pool-Heater data from Ken Sheinkopf, Solar Today, Nov/Dec 1997, pp. 22-25. 

1980 1985 1990 1995 2000 2005 2010 

Capital Cost* ($/System)  Domestic Hot-Water Heater 1,900 - 2,500  Pool Heater 3,300 - 4,000 O&M ($/System-yr)  Domestic Hot-Water Heater 25 - 30  Pool Heater 0 * Costs represent a range of technologies, with the lower bounds representing advanced technologies, such as a low-cost 

domestic hot-water heaters, which are expected to become commercially available after 2010. 

64
Reciprocating Engines

Technology Description 

Reciprocating engines, also known as 

internal combustion engines, require 

fuel, air, compression, and a combustion 

source to function. They make up the 

largest share of the small power 

generation market and can be used in a 

variety of applications due to their small 

size, low unit costs, and useful thermal 

output. 

System Concepts 

• Reciprocating engines fall into one of two categories depending on the ignition source: spark 

ignition (SI), typically fueled by gasoline or natural gas; or compression ignition (CI), typically fueled 

by diesel oil. 

• Reciprocating engines also are categorized by the number of revolutions it takes to complete a 

combustion cycle. A two-stroke engine completes its combustion cycle in one revolution and a fourstroke engine completes the combustion process in two revolutions. 

Representative Technologies 

• The four-stroke SI engine has an intake, compression, power, and exhaust cycle. In the intake 

stroke, as the piston moves downward in its cylinder, the intake valve opens and the upper portion of 

the cylinder fills with fuel and air. When the piston returns upward in the compression cycle, the spark 

plug fires, igniting the fuel/air mixture. This controlled combustion forces the piston down in the power 

stroke, turning the crankshaft and producing useful shaft power. Finally the piston moves up again, 

exhausting the burnt fuel and air in the exhaust stroke. 

• The four-stroke CI engine operates in a similar manner, except diesel fuel and air ignite when the 

piston compresses the mixture to a critical pressure. At this pressure, no spark or ignition system is 

needed because the mixture ignites spontaneously, providing the energy to push the piston down in the 

power stroke. 

• The two-stroke engine, whether SI or CI, has a higher power density, because it requires half as 

many crankshaft revolutions to produce power. However, two-stroke engines are prone to let more fuel 

pass through, resulting in higher hydrocarbon emissions in the form of unburned fuel. 

Technology Applications 

• Reciprocating engines can be installed to accommodate baseload, peaking, emergency or standby 

power applications. Commercially available engines range in size from 10 kW to more than 7 MW 

making them suitable for many distributed-power applications. Utility substations and small 

municipalities can install engines to provide baseload or peak shaving power. However, the most 

promising markets for reciprocating engines are on-site at commercial, industrial, and institutional 

facilities. With fast start-up time, reciprocating engines can play integral backup roles in many building 

energy systems. On-site reciprocating engines become even more attractive in regions with high 

electric rates (energy/demand charges). 

• When properly treated, the engines can run on fuel generated by waste treatment (methane) and 

other biofuels. 

• By using the recuperators that capture and return waste exhaust heat, reciprocating engines can be 

used in combined heat and power (CHP) systems to achieve energy efficiency levels approaching 80%. 

In fact, reciprocating engines make up a large portion of the CHP or cogeneration market. 

65
Current Status 

• Commercially available engines have electrical efficiencies (LHV) between 28% and 50% and 

yield NOx emissions of 0.5-2.0 grams per horsepower hour (hp-hr) for lean-burn natural gas engines 

and 3.5-6.0 g/bhp-hr for conventional dual-fuel engines. CHP engines achieve electrical efficiencies 

(LHV) of 70-80%. 

• Installed cost for reciprocating engines range between $695 and $1,350/ kW depending on size and 

whether the unit is for a straight generation or cogeneration application. Operating and maintenance 

costs range 0.8 -1.8 ¢/kWh. Production costs are generally lowest for high-speed engines. 

• Exhaust temperature for most reciprocating engines is 700-1200° F in non-CHP mode and 350-

500°F in a CHP system after heat recovery. 

• Noise levels with sound enclosures are typically between 70-80 dB. 

• The reciprocating-engine systems typically include several major parts: fuel storage, handling, and 

conditioning, prime mover (engine), emission controls, waste recovery (CHP systems) and rejections 

(radiators), and electrical switchgear. 

• Annual shipments of reciprocating engines (sized 10MW or less) have almost doubled to 18 GW 

between 1997 and 2000. The growth is overwhelming in the diesel market, which represented 16 GW 

shipments compared with 2 GW of natural gas reciprocating engine shipments in 2000. 

• The cost of full maintenance contracts range from 0.7 to 2.0 cents/kWh. Remote monitoring is now 

available as a part of service contracts. 

(Source: Diesel and Gas Turbine Worldwide).

Key indicators for stationary reciprocating engines: 

Installed Worldwide 

Capacity 

Installed US 

Capacity 

Number of CHP sites using 

Recips in the U.S. in 2000 

146 GW 52 GW 1,055 

Sources: Distributed Generation: The Power Paradigm for the New Millenium, 2001; "Gas Fired Distributed 

Energy Resource Technology Characterizations (2003)." 

Manufacturers of reciprocating engines include: 

Caterpillar 

Coast Intelligen, Inc. 

Cooper Energy Systems 

Cummins 

Fairbanks-Morse Engine Company 

Hess Microgen, Inc. 

Jenbacher 

Kohler Power Systems 

Tecogen, Inc. 

Wartsila 

Waukesha 

Technology History 

• Natural gas-reciprocating engines have been used for power generation since the 1940s. The 

earliest engines were derived from diesel blocks and incorporated the same components of the diesel 

engine. Spark plugs and carburetors replaced fuel injectors, and lower compression-ratio pistons were 

substituted to run the engine on gaseous fuels. These engines were designed to run without regard to 

fuel efficiency or emission levels. They were used mainly to produce power at local utilities and to 

drive pumps and compressors. 

• In the mid-1980s, manufacturers were facing pressure to lower NOx emissions and increase fuel 

economy. Leaner air-fuel mixtures were developed using turbochargers and charge air coolers, and in 

combination with lower in-cylinder fire temperatures, the engines reduced NOx from 20 to 5 g/bhp-hr. 

The lower in-cylinder fire temperatures also meant that the BMEP (Brake Mean Effective Pressure) 

could increase without damaging the valves and manifolds. 

66
• Reciprocating-engine sales have grown more then five-fold from 1988 (2 GW) to 1998 (11.5 GW). 

Gas-fired engine sales in 1990 were 4% compared to 14% in 1998. The trend is likely to continue for 

gas-fired reciprocating engines due to strict air-emission regulations and because performance has been 

steadily improving for the past 15 years. 

• More than 35 million reciprocating engine units are produced in North America annually for 

automobiles, trucks, construction and mining equipment, marine propulsion, lawn care and a diverse 

range of power generation applications. 

Technology Future

The U.S. Department of Energy, in partnership with the Gas Technology Institute, the Southwest 

Research Institute, and equipment manufacturers, supports the Advanced Reciprocating Engines 

Systems (ARES) consortium, aimed at further advancing the performance of the engine. Performance 

targets include: 

High Efficiency- Target fuel-to-electricity conversion efficiency (LHV) is 50 % by 2010. 

Environment – Engine improvements in efficiency, combustion strategy, and emissions reductions will 

substantially reduce overall emissions to the environments. The NOx target for the ARES program is 

0.1 g/hp-hr, a 90% decrease from today’s NOx emissions rate. 

Fuel Flexibility – Natural gas-fired engines are to be adapted to handle biogas, renewables, propane 

and hydrogen, as well as dual fuel capabilities. 

Cost of Power – The target for energy costs, including operating and maintenance costs is 10 % less 

than current state-of-the-art engine systems. 

Availability, Reliability, and Maintainability – The goal is to maintain levels equivalents to current 

state-of-the-art systems. 

Other R&D directions include: new turbocharger methods, heat recovery equipment specific to the 

reciprocating engine, alternate ignition system, emission-control technologies, improved generator 

technology, frequency inverters, controls/sensors, higher compression ratio, and dedicated natural-gas 

cylinder heads. 

Source: National Renewable Energy Laboratory. Gas-Fired Distributed Energy Resource Technology 

Characterizations. NREL/TP-620-34783. November 2003.

67
Reciprocating Engines 

Technology Performance 

Power Ranges (kW) of Selected Manufacturers Source: Manufacturer Specs 

Low High

Caterpillar 150 3,350 Waukesha 200 2,800 Cummins 5 1,750 Jenbacher 200 2,600 Wartsila 500 5,000 Market Data 

Market Shipments 

Source: Debbie Haught, DOE, communication 2/26/02 - from Diesel and Gas Worldwide. 

(GW of units under 10 MW in size)  1996 1997 1998 1999 Diesel Recips 7.96 7.51 8.23 10.02 1Gas Recips 0.73 1.35 1.19 1.63 

68
Microturbines

Technology Description 

Microturbines are small combustion 

turbines of a size comparable to a 

refrigerator and with outputs of 30 kW to 

400 kW. They are used for stationary 

energy generation applications at sites with 

space limitations for power production. 

They are fuel-flexible machines that can 

run on natural gas, biogas, propane, butane, 

diesel, and kerosene. Microturbines have 

few moving parts, high efficiency, low 

emissions, low electricity costs, and waste 

heat utilization opportunities; and are 

lightweight and compact in size. Waste 

heat recovery can be used in combined heat 

and power (CHP) systems to achieve energy efficiency levels greater than 80%. 

System Concepts

• Microturbines consist of a compressor, combustor, turbine, alternator, recuperator, and generator. 

• Microturbines are classified by the physical arrangement of the component parts: single shaft or 

two-shaft, simple cycle or recuperated, inter-cooled, and reheat. The machines generally operate at 

more than 40,000 rpm, while some machines operate at more than 100,000 rpm. 

• A single shaft is the more common design because it is simpler and less expensive to build. 

Conversely, the split shaft is necessary for machine-drive applications, which do not require an 

inverter to change the frequency of the AC power. 

• Efficiency gains can be achieved with greater use of materials like ceramics, which perform well at 

higher engine-operating temperatures. 

 

Representative Technologies 

• Microturbines in a simple cycle, or unrecuperated, turbine; heated, compressed air is mixed with 

fuel and burned under constant pressure conditions. The resulting hot gas is allowed to expand 

through a turbine to perform work. Simple-cycle microturbines have lower cost, higher reliability, 

and more heat available for CHP applications than recuperated units. 

• Recuperated units use a sheet-metal heat exchanger that recovers some of the heat from an exhaust 

stream and transfers it to the incoming air stream. The preheated air is then used in the combustion 

process. If the air is preheated, less fuel is necessary to raise its temperature to the required level at 

the turbine inlet. Recuperated units have a higher efficiency and thermal-to-electric ratio than 

unrecuperated units, and yield 30-40% fuel savings from preheating. 

Technology Applications 

• Microturbines can be used in a wide range of applications in the commercial, industrial, and 

institutional sectors, microgrid power parks, remote off-grid locations, and premium power markets. 

• Microturbines can be used for backup power, baseload power, premium power, remote power, grid 

support, peak shaving, cooling and heating power, mechanical drive, and use of wastes and biofuels. 

• Microturbines can be paired with other distributed energy resources such as energy-storage devices 

and thermally activated technologies. 

69
Current Status 

• Microturbine systems have recently entered the market and the manufacturers are targeting both 

traditional and nontraditional applications in the industrial and buildings sectors, including CHP, 

backup power, continuous power generation, and peak shaving.

• The most popular microturbine installed to date is the 30-kW system manufactured by Capstone. 

Microturbine efficiencies are 25-29% (LHV).

• The typical 30 kW unit package cost averages $1,100/kW. For gas-fired microturbines, the present 

installation cost (site preparation and natural gas hookup) for a typical 30 kW commercial unit averages 

$2,263/kW for power only systems and $2,636 for CHP systems. Service contracts are available at 1 to 

2 cents/kWh

• Honeywell pulled out of the microturbine business in December 2001, leaving the following 

manufacturers in the microturbine market:

Capstone Turbine Corporation 

Elliot Energy Systems 

Turbec 

Ingersoll-Rand 

Bowman Power 

• Capstone, Ingersoll-Rand, Elliott, and Turbec combined have shipped more than 2,100 units (156 

MW) worldwide during the past four years. 

Technology History 

• Microturbines represent a relatively new technology, which entered the commercial market in 

1999-2000. The technology used in microturbines is derived from aircraft auxiliary power systems, 

diesel-engine turbochargers, and automotive designs. 

• In 1988, Capstone Turbine Corporation began developing the microturbine concept; and in 1998, 

Capstone was the first manufacturer to offer commercial power products using microturbine 

technology. 

Technology Future

• The market for microturbines is expected to range from $2.4-to-$8 billion by 2010, with 50% of 

sales concentrated in North America. 

• The acceptable cost target for microturbine energy is $0.05/kWh, which would present a cost 

advantage over most nonbaseload utility power. 

• The next generation of "ultra-clean, high-efficiency" microturbine product designs will focus on 

the following DOE performance targets: 

− High Efficiency — Fuel-to-electricity conversion efficiency of at least 40%. 

− Environment — NOx < 7 ppm (natural gas). 

− Durability — 1,000 hours of reliable operations between major overhauls and a service life of at 

least 45,000 hours. 

− Cost of Power — System costs < $500/kW, costs of electricity that are competitive with 

alternatives (including grid) for market applications by 2005 (for units in the 30-60 kW range) 

− Fuel Flexibility — Options for using multiple fuels including diesel, ethanol, landfill gas, and 

biofuels. 

Source: National Renewable Energy Laboratory. Gas-Fired Distributed Energy Resource Technology 

Characterizations. NREL/TP-620-34783. November 2003.

70
Microturbines 

Market Data 

Microturbine Shipments Source: Debbie Haught, communications 2/26/02. 

 Capstone sales reported in Quarterly SEC filings, others estimated. No. of units 1998 1999 2000 200Capstone 2 211 790 1,03Other Manufacturers 12MW Capstone 6 23.7 38Other Manufacturers 10

Technology Performance 

 Source: Manufacturer Surveys, Arthur D. Little (ADL) estimates. Current System Efficiency (%) LHV: 17-20% unrecuperated, 25-30%+ recuperated 

Lifetime (years) 5-10 years, depending on duty cycle Emissions (natural gas fuel) Current  CO2 670 - 1,180 g/kWh (17-30% efficiency)  SO2 Negligible (natural gas)  NOx 9-25 ppm  CO 25-50 ppm  PM Negligible  Current Products: 25-100 kW Typical System Size 

 Units can be bundled or "ganged" to produce power in larger incr

Maintenance Requirements (Expected) 10,000-12,000 hr before major overhaul (rotor replacement) Footprint [ft2/kW] 0.2-0.4 

71
Technology Performance 

Sources: Debbie Haught, DOE, communication 2/26/02 and Energetics, Inc. Distributed Energy Microturbine Validation, July 12 2001. 

Capstone Turbine Corporation

Elliot Energy 

Systems 

Ingersoll-Rand Energy 

Services Turbec 

Model Name Model 330 Capstone 60 TA-80 PowerWorks Size 30 kW 60 kW 80 kW 70 kW 100 kW Voltage 400-480 VAC 400 VAC Fuel Flexibility natural gas, medium Btu gas, diesel, kerosene natural gas natural gas natural gas, biog

ethanol, diese

Fuel Efficiency (cf/kWh) 13.73 14.23 11.2 

26% (+/-2%) 28% (+/- 2%) 28% 30-33% 30% 

Efficiency 70-90% CHP 70-90% CHP 80% CHP 80% CHP Emissions NOx <9ppmV @15% O2

NOx diesel <60ppm, 

NOx NG <25ppm, CO 

diesel <400ppm, CO 

NG <85ppm 

NOx <9ppmV @15% 

O2, CO <9ppmV @15% 

O2

NOx <15ppmV 

@15% O2, CO 

<15ppm, UHC 

<10ppm 

1999: 211 units 

Units Sold 2000: 790 units 

2001: 1,033 units 2001: 100 units 

2000: 2 precommercial 

units, expected 

commercial in 2001 

2000: 20 units 

the European 

market 

Unit Cost $1000/kW $75,000 Cold Start-Up Time 3 min Web site www.capstone.com

www.elliottturbo.com/new/produ

cts_microtubines.html

www.irco.com/energy systems/powerworks. html 

www.turbec.com

72
Fuel Cells

Technology Description 

A fuel cell is an electrochemical energy 

conversion device that converts hydrogen and 

oxygen into electricity and water. This unique 

process is practically silent, nearly eliminates 

emissions, and has no moving parts. 

System Concepts

• Similar to a battery, fuel cells have an anode 

and a cathode separated by an electrolyte. 

• Hydrogen enters the anode and air (oxygen) 

enters the cathode. The hydrogen and oxygen 

are separated into ions and electrons, in the presence of a catalyst. Ions are conducted through the 

electrolyte while the electrons flow through the anode and the cathode via an external circuit. The current 

produced can be utilized for electricity. The ions and electrons then recombine, with water and heat as the 

only byproducts. 

• Fuel cell systems today typically consist of a fuel processor, fuel cell stack, and power conditioner. 

The fuel processor, or reformer, converts hydrocarbon fuels to a mixture of hydrogen-rich gases and, 

depending on the type of fuel cell, can remove contaminants to provide pure hydrogen. The fuel cell stack 

is where the hydrogen and oxygen electrochemically combine to produce electricity. The electricity 

produced is direct current (DC) and the power conditioner converts the DC electricity to alternating 

current (AC) electricity, for which most of the end-use technologies are designed. As a hydrogen 

infrastructure emerges, the need for the reformer will disappear as pure hydrogen will be available near 

point of use. 

Representative Technologies 

• Fuel cells are categorized by the kind of electrolyte they use. 

• Alkaline Fuel Cells (AFCs) were the first type of fuel cell to be used in space applications. AFCs 

contain a potassium hydroxide (KOH) solution as the electrolyte and operate at temperatures between 

60 and 260°C (140 to 500°F). The fuel supplied to an AFC must be pure hydrogen. Carbon monoxide 

poisons an AFC, and carbon dioxide (even the small amount in the air) reacts with the electrolyte to 

form potassium carbonate. 

• Phosphoric Acid Fuel Cells (PAFCs) were the first fuel cells to be commercialized. These fuel cells 

operate at 190-210°C (374-410°F) and achieve 35 to 45% fuel-to-electricity efficiencies LHV. 

Commercially-validated reliabilities are 90-95%. The largest market barrier is cost ($4,500 - 

$5,500/kW), which is why PAFCs are being phased out of commercial production 

• Proton Exchange Membrane Fuel Cells (PEMFCs) operate at relatively low temperatures of 70-100°C 

(150-180°F), have high power density, can vary their output quickly to meet shifts in power demand, 

and are suited for applications where quick start-up is required (e.g., transportation and power 

generation). The PEM is a thin fluorinated plastic sheet that allows hydrogen ions (protons) to pass 

through it. The membrane is coated on both sides with highly dispersed metal alloy particles (mostly 

platinum) that are active catalysts. 

• Molten Carbonate Fuel Cell (MCFC) technology has the potential to reach fuel-to-electricity 

efficiencies of 45 to 60% on a higher heating value basis (HHV). Operating temperatures for MCFCs 

are around 650° C (1,200°F), which allows total system thermal efficiencies up to 50% HHV in 

combined-cycle applications. MCFCs have been operated on hydrogen, carbon monoxide, natural gas, 

propane, landfill gas, marine diesel, and simulated coal gasification products. 

73
• Solid Oxide Fuel Cells (SOFCs) operate at temperatures up to 1,000°C (1,800°F), which further 

enhances combined-cycle performance. A solid oxide system usually uses a hard ceramic material 

instead of a liquid electrolyte. The solid-state ceramic construction enables the high temperatures, 

allows more flexibility in fuel choice, and contributes to stability and reliability. As with MCFCs, 

SOFCs are capable of fuel-to-electricity efficiencies of 45% to 55% LHV and total system thermal 

efficiencies up to 85% LHV in combined-cycle applications. 

Technology Applications 

• Fuel cell systems can be sized for grid-connected applications or customer-sited applications in 

residential, commercial, and industrial facilities. Depending on the type of fuel cell (most likely SOFC and 

MCFC), useful heat can be captured and used in combined heat and power systems (CHP). 

• Premium power applications are an important niche market for fuel cells. Multiple fuel cells can be 

used to provide extremely high (more then six-nines) reliability and high-quality power for critical loads. 

• Data centers and sensitive manufacturing processes are ideal settings for fuel cells. 

• Fuel cells also can provide power for vehicles and portable power. PEMFCs are a leading candidate for 

powering the next generation of vehicles. The military is interested in the high-efficiency, low-noise, 

small-footprint portable power. 

Current Status 

• Fuel cells are still too expensive to compete in widespread domestic and international markets without 

significant subsidies. 

• PAFC – More than 250 PAFC systems are in service worldwide, with those installed by ONSI having 

surpassed 2 million total operating hours with excellent operational characteristics and high availability. 

 

 Economic Specifications of the PAFC (200 kW) 

Expense Description Cost 

Capital Cost 1 complete PAFC power plant $850,000 

Installation Electrical, plumbing, and foundation $40,000 

Operation Natural gas costs $5.35/MMcf 

Minor Maintenance Service events, semiannual and annual maintenance $20,000/yr 

Major Overhaul Replacement of the cell stack $320,000/5 yrs 

Source: Energetics, Distributed Energy Technology Simulator: Phosphoric Acid Fuel Cell Validation, May 2001. 

PEMFC – Ballard’s first 250 kW commercial unit is under test. PEM systems up to 200 kW are also 

operating in several hydrogen-powered buses. Most units are small (<10 kW). PEMFCs currently cost 

several thousand dollars per kW. 

SOFC – A small, 25 kW natural gas tubular SOFC systems has accumulated more than 70,000 hours of 

operations, displaying all the essential systems parameters needed to proceed to commercial 

configurations. Both 5 kW and 250 kW models are in demonstration. 

MCFC – 50 kW and 2 MW systems have been field-tested. Commercial offerings in the 250 kW-2 MW 

range are under development. 

74
Some fuel cell developers include: 

Acumentrics Corporation 

Anuva Corporation 

Avista Laboratories 

Ballard Power Systems, Inc 

Ceramatec 

Electrochem, Inc. 

FuelCell Energy 

Hydrogenics Corporation 

IdaTech 

McDermitt Technologies, Inc. 

Mitsubishi Electric Corporation 

ONSI Corporation (IFC/United Technologies) 

Plug Power, LLC 

Siemens Westinghouse Power Corporation 

Solid State Energy Conversion Alliance 

Toshiba Corporation 

UTC Fuel Cells 

Ztek Corporation 

Fuel Cell 

Type Electrolyte 

Operating 

Temp 

(°C) 

Electrical 

Efficiency 

(% HHV) 

Commercial 

Availability 

Typical Unit 

Size Range 

Startup time 

(hours) 

AFC KOH 260 32-40 1960s 

PEMFC Nafion 65-85 30-40 2000-2001 5-250 kW < 0.1 

PAFC Phosphoric 

Acid 190-210 35-45 1992 200 kW 1-4 

MCFC 

Lithium, 

potassium, 

carbonate salt 

650-700 40-50 Post 2003 250 kW-2 

MW 5-10 

SOFC 

Yttrium & 

zirconium 

oxides 

750-1000 45-55 Post 2003 5-250 kW 5-10 

Sources: Anne Marie Borbely and Jan F. Kreider. Distributed Generation: The Power Paradigm for the New 

Millennium, CRC Press, 2001, and Arthur D. Little, Distributed Generation Primer: Building the Factual Foundation 

(multiclient study), February 2000 

Technology History 

• In 1839, William Grove, a British jurist and amateur physicist, first discovered the principle of the fuel 

cell. Grove utilized four large cells, each containing hydrogen and oxygen, to produce electric power 

which was then used to split the water in the smaller upper cell into hydrogen and oxygen. 

• In the 1960s, alkaline fuel cells were developed for space applications that required strict 

environmental and efficiency performance. The successful demonstration of the fuel cells in space led to 

their serious consideration for terrestrial applications in the 1970s. 

• In the early 1970s, DuPont introduced the Nafion® membrane, which has traditionally become the 

electrolyte for PEMFC. 

• In 1993, ONSI introduced the first commercially available PAFC. Its collaborative agreement with the 

U.S. Department of Defense enabled more than 100 PAFCs to be installed and operated at military 

installations. 

• The emergence of new fuel cell types (SOFC, MCFC) in the past decade has led to a tremendous 

expansion of potential products and applications for fuel cells. 

75
Technology Future

• According to the Business Communications Company, the market for fuel cells was about $218 

million in 2000, will increase to $2.4 billion by 2004, and will reach $7 billion by 2009. 

• Fuel cells are being developed for stationary power generation through a partnership of the U.S DOE 

and the private sector. 

• Industry will introduce high-temperature natural gas-fueled MCFC and SOFC at $1,000 -$1,500 per 

kW that are capable of 60% efficiency, ultra-low emissions, and 40,000 hour stack life. 

• DOE is also working with industry to test and validate the PEM technology at the 1–kW level and to 

transfer technology to the Department of Defense. Other efforts include raising the operating temperature 

of the PEM fuel cell for building, cooling, heating, and power applications and improve reformer 

technologies to extract hydrogen from a variety of fuels, including natural gas, propane, and methanol. 

Sources: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003; and National 

Renewable Energy Laboratory. Gas-Fired Distributed Energy Resource Technology Characterizations. 

NREL/TP-620/34783. November 2003.

76
Fuel Cells 

Technology Performance 

 Source: Arthur D. Little (ADL) estimates, survey of equipment manufacturers.  Only industrial applications; table does not address residential/commercial-scale fuel cel

2000 Characteristics 2005 Characterist

Installed Cost 

($/kW) 

Non-Fuel O&M 

(cents/kWh) 

Electrical 

Efficiency (LHV) 

Installed Cost 

($/kW) 

Non-Fuel O&M 

(cents/kWh) 

Technology 

Size Range 

(kW) Low High Low High High Low Low High Low High 

Low Temperature Fuel Cell (PEM) 200-250 2,000 3,000 1.5 2.0 40% 30% 1,000 2,000 1.0 1.8 High Temperature Fuel Cell (SOFC & MCFC) 

250-1,000 NA 1,500 2,000 1.0 2.0 

Source: Energetics, Distributed Energy Technology Simulator: PAFC Validation, May 20

 Size (kW) Capital Cost Installation (Site Preparation) Operation Costs (Natural Gas) Minor Maintenance Major OverhauInstallation of a commercially available PAFC 

200 $850,000 $40,000 $5.35/MMcf $20,000/yr $320,000/5 yrs 

77
Technology Performance 

There have been more than 25 fuel cell demonstrations funded by the private sector, the government, or a cofunded partne

objectives for most have been to validate a specific technology advance or application, and most of these demonstrations hthe Office of Fossil Energy. This is a listing of the demonstrations that have taken place between 1990 and today that have been published. All of the d

deemed a success, even if the testing had to end before its scheduled completion point. All of the manufacturers claimed th

from each test. All the OPT-funded demonstrations were used to prove new higher performance-based technology either w

levels, metal separator plates, carbon paper in lieu of machined carbon plates, or new membrane materials. Only the Plug 

for the Remote Power Project failed, due to an electrical fire. 

Fuel Cell Type Company Objective Phosphoric Acid Fuel Cell UT Fuel Cells (IFC)/FE 12.5 kW prototype using a new membrane assembl

40 kW power plant (46 units) 100 kW prototype for Georgetown Bus. (2 units) Me200 kW first manufacturing prototype for PC25 (4 ungas reformer 

Phosphoric Acid Fuel Cell IFC/OPT 200 kW hydrogen version of PC 25 without a reform

assembly 

Solid Oxide Westinghouse/FE 2 MW SOFC at Toshiba for fuels and tubular geome

100 kW plannar unit to test seals, Netherlands 250 kW hybrid(57/50) w/turbine SoCal Ed 250 kW tubular SOFC combined heat and power, O

Molten Carbonate Fuel Cell Energy/FE 250 kW 8,800 hours Danbury Ct. first precommercia

3 MW four years to build, Lexington Clean Coal Proj2 MW San Diego failed early 

Proton Exchange Membrane Plug Power/OTT 

Plug Power/OPT 

10 kW prototype for vehicles 50 kW unsuccessful 25 kW prototype for Alaska, integrated with diesel re50 kW prototype for Las Vegas refueling station, inte

gas reformer 

78
Proton Exchange Membrane IFC/OTT 10 kW prototype sent to LANL for evaluation 

50 kW prototype sent to GM for evaluation, reduced 75 kW prototype installed in Hundai SUV, prototype devices 

Proton Exchange Membrane Schatz Energy Center/OPT (3) 5 kW Personal Utility Vehicles, (1) 15 kW Neighb

Vehicle Palm Desert each incorporated different levdifferent membranes, all hydrogen fueled 1.3 kW Portable Power Unit 

Proton Exchange Membrane Enable/OPT (3) 100 W Portable Power Units to demonstrate rad

(2) 1.5 kW Portable Power Units incorporating the Lcell design (1) 1 kW “air breather” design for wheelchair 

Proton Exchange Membrane Ballard: no DOE funds (6) 250 kW 40 foot passenger buses, hydrogen fuele

Vancouver, 1 Palm Desert (1) 100 kW powerplant for Ford “Think” car (1) 250 kW stationary powerplant new manufacturin

Proton Exchange Membrane Nuvera/OPT 3 kW powerplant using metal separator plate techno

evaluated by SNL and University of Alaska 

Proton Exchange Membrane Coleman Powermate/Ballard 

no DOE funds 

(3) 1.3 kW precommercial prototype UPS systems, mstorage, under evaluation at United Laboratories for 

Proton Exchange Membrane Reliant Energy 7.5 kW precommercial prototype of radial stack geo

conductive plastic separator plates 

Alkaline Zetec 25 kW precommercial prototype to demonstrate reg

dioxide scrubber 

Alkaline Hamilton Standard/IFC (100) 12.5 kW commercial units for NASA Alkaline Union Carbide (2) 50 kW fuel cells for GM van and car 

79
80
Batteries

Technology Description 

Batteries are likely the most widely known type 

of energy storage. They all store and release 

electricity through electrochemical processes and 

come in a variety of shapes and sizes. Some are 

small enough to fit on a computer circuit board 

while others are large enough to power a 

submarine. Some batteries are used several times 

a day while others may sit idle for 10 or 20 years 

before they are ever used. Obviously for such a 

diversity of uses, a variety of battery types are 

necessary. But all of them work from the same 

basic principles. 

System Concepts 

Battery electrode plates, typically consisting of 

chemically reactive materials, are placed in an electrolyte, which facilitates the transfer of ions in the 

battery. The negative electrode gives up electrons during the discharge cycle. This flow of electrons 

creates electricity that is supplied to any load connected to the battery. The electrons are then transported 

to the positive electrode. This process is reversed during charging. Batteries store and deliver direct 

current (DC) electricity. Thus, power-conversion equipment is required to connect a battery to the 

alternating current (AC) electric grid. 

Representative Technologies 

• The most mature battery systems are based on lead-acid technology. There are two major kinds of 

lead acid batteries: flooded lead acid batteries and valve-regulated-lead-acid (VRLA) batteries. 

• There are several rechargeable, advanced batteries under development for stationary and mobile 

applications, including lithium-ion, lithium polymer, nickel metal hydride, zinc-air, zinc-bromine, 

sodium sulfur, and sodium bromide. 

• These advanced batteries offer potential advantages over lead acid batteries in terms of cost, energy 

density, footprint, lifetime, operating characteristics reduced maintenance, and improved performance. 

Technology Applications 

• Lead-acid batteries are the most common energy storage technology for stationary and mobile 

applications. They offer maximum efficiency and reliability for the widest variety of stationary 

applications: telecommunications, utility switchgear and control, uninterruptible power supplies (UPS), 

photovoltaic, and nuclear power plants. They provide instantaneous discharge for a few seconds or a few 

hours. 

• Installations can be any size. The largest system to date is 20 MW. Lead-acid batteries provide 

power quality, reliability, peak shaving, spinning reserve, and other ancillary services. The 

disadvantages of the flooded lead-acid battery include the need for periodic addition of water, and the 

need for adequate ventilation since the batteries can give off hydrogen gas when charging. 

• VRLA batteries are sealed batteries fitted with pressure-release valves. They have been called lowmaintenance batteries because they do not require periodic adding of water. They can be stacked 

horizontally as well as vertically, resulting in a smaller footprint than flooded lead-acid batteries. 

Disadvantages include higher cost and increased sensitivity to the charging cycle used. High temperature 

results in reduced battery life and performance. 

81
• Several advanced “flow batteries” are under development. The zinc-bromine battery consists of a 

zinc positive electrode and a bromine negative electrode separated by a microporous separator. An 

aqueous solution of zinc/bromide is circulated through the two compartments of the cell from two 

separate reservoirs. Zinc-bromine batteries are currently being demonstrated in a number of hybrid 

installations, with microturbines and diesel generators. Sodium bromide/sodium bromine batteries are 

similar to zinc-bromine batteries in function and are under development for large-scale, utility 

applications. The advantages of flow-battery technologies are low cost, modularity, scalability, 

transportability, low weight, flexible operation, and all components are easily recyclable. Their major 

disadvantages are a relatively low cycle efficiency. 

• Other advanced batteries include the lithium-ion, lithium-polymer, and sodium-sulfur batteries. The 

advantages of lithium batteries include their high specific energy (four times that of lead-acid batteries) 

and charge retention. Sodium sulfur batteries operate at high temperature and are being tested for utility 

load-leveling applications. 

Current Status 

• Energy storage systems for large-scale power quality applications (~10 MW) are economically 

viable now with sales from one manufacturer doubling from 2000 to 2001. 

• Lead-acid battery annual sales have tripled between 1993 and 2000. The relative importance of 

battery sales for switchgear and UPS applications shrunk during this period from 45% to 26% of annual 

sales by 2000. VRLA and flooded battery sales were 534 and 171 million dollars, respectively, in 2000. 

Recently, lead-acid battery manufacturers have seen sales drop with the collapse of the 

telecommunications bubble in 2001. They saw significant growth in sales in 2000, due to the demand 

from communications firms, and invested in production and marketing in anticipation of further growth. 

• Many manufacturers have been subject to mergers and acquisitions. A few dozen manufacturers in 

the United States and abroad still make batteries. 

• Government and private industry are currently developing a variety of advanced batteries for 

transportation and defense applications: lithium-ion, lithium polymer, nickel metal hydride, sodium 

metal chloride, sodium sulfur, and zinc bromine. 

• Rechargeable lithium batteries already have been introduced in the market for consumer electronics 

and other portable equipment. 

• There are two demonstration sites of ZBB’s Zinc Bromine batteries in Michigan and two additional 

ones in Australia. 

• Utility-grade batteries are sized 17-40 MWh and range in efficiency from 70 to 80%. Such batteries 

have power densities ranging from 0.2 to 0.4 kW/kg and 30-50 Wh/kg in energy density. 

• Batteries are the most common energy storage device. 

• Currently, about 150 MW of utility peak-shaving batteries are in use in Japan. 

• Two 10-MW flow battery systems are under construction; one system is in the U.K. and the other 

system is in the United States. 

Representative Current Manufacturers 

Flooded VRLA Nickel Cadmium, 

Lithium Ion Zinc Bromine 

East Penn 

Exide 

Rolls 

Trojan 

Hawker 

GNB 

Panasonic 

Yuasa 

SAFT 

Sanyo 

Panasonic 

Medentia 

Powercell 

ZBB 

82
Technology History 

• Most historians date the invention of batteries to about 1800 when experiments by Alessandro Volta 

resulted in the generation of electrical current from chemical reactions between dissimilar metals. 

• Secondary batteries date back to 1860 when Raymond Gaston Planté invented the lead-acid battery. 

His cell used two thin lead plates separated by rubber sheets. He rolled the combination up and 

immersed it in a dilute sulfuric acid solution. Initial capacity was extremely limited since the positive 

plate had little active material available for reaction. 

• Others developed batteries using a paste of lead oxides for the positive plate active materials. This 

allowed much quicker formation and better plate efficiency than the solid Planté plate. Although the 

rudiments of the flooded lead-acid battery date back to the 1880s, there has been a continuing stream of 

improvements in the materials of construction and the manufacturing and formation processes. 

• Since many of the problems with flooded lead-acid batteries involved electrolyte leakage, many 

attempts have been made to eliminate free acid in the battery. German researchers developed the gelledelectrolyte lead-acid battery (a type of VRLA) in the early 1960s. Working from a different approach, 

Gates Energy Products developed a spiral-wound VRLA cell, which represents the state of the art today. 

Technology Future

• Lead-acid batteries provide the best long-term power in terms of cycles and float life and, as a result, 

will likely remain a strong technology in the future. 

• Energy storage and battery systems in particular will play a significant role in the Distributed Energy 

Resource environment of the future. Local energy management and reliability are emerging as important 

economic incentives for companies. 

• A contraction in sales of lead-acid batteries that began in 2001 was expected to continue over the 

next few years until 9/11 occurred. Military demand for batteries may drastically alter the forecast for 

battery sales. 

• Battery manufacturers are working on incremental improvements in energy and power density. 

The battery industry is trying to improve manufacturing practices and build more batteries at lower costs 

to stay competitive. Gains in development of batteries for mobile applications will likely crossover to the 

stationary market. 

• Zinc Bromine batteries are expected to be commercialized in 2003 with a target cost of $400/kWh. 

A 10 MW-120 MWh sodium bromide system is under construction by the Tennessee Valley Authority 

A 40 MW nickel cadmium system is being built for transmission-line support and stabilization in 

Alaska. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

83
Batteries

Market Data 

Recent Battery Sales Source: Battery Council International, Annual Sales Summary, October 2001. 

1993 2000 Growth 

Flooded Batteries (Million $) 156.9 533.5 340% VRLA Batteries (Million $) 79.6 170.6 214% Total Lead-Acid Batteries (Million $) 236.5 704.1 298% Percent Communications 58% 69% Percent Switchgear/UPS 45% 26% Market Predictions Source: Sandia National Laboratories, Battery Energy  Storage Market Feasibility Study, September 1997. 

Year MW ($ Million) 

2000 496 372 2005 805 443 2010 965 434 

84
Technology Performance 

Grid-Connected Energy Storage Technologies Costs and Efficiencies 

Source: Sandia National Laboratories, Characteristics and Technologies for Long- vs. Short-Term Energy Storage, March 2001. 

Energy-Storage System Energy Related 

Cost ($/kWh) 

Power Related Cost ($/kW) Balance of Plant 

($/kWh) Dis

Lead-acid Batteries 

low 175 200 50 

average 225 250 50 

high 250 300 50 

Power-Quality Batteries 100 250 40 Advanced Batteries 245 300 40 Technology Performance 

Off-Grid Storage Applications, Their Requirements, and Potential Markets to 2010 According to Boeing 

Source: Sandia National Laboratories, Energy Storage Systems Program Report for FY99, June 2000. 

Application Single Home: 

Developing 

Community 

Developing Community: No Industry Developing 

Community: 

Light Industry 

M

Storage-System Attributes 

Power (kW) 0.5 8 40 

Energy (kWh) 3 45 240 

Power 

Base (kW) 0.5 5 10 Peak (kW) < 8 < 40 

Discharge Duration 5 to 72 hrs 5 to 72 hrs 5 to 24 hrs Total Projected Number of Systems 47 Million 137,000 40,000 Fraction of Market Captured by Storage > 50 > 50 ~ 30 Total Number of Storage Systems to 24 Million 69,000 12,000 Capture Market Share 

85
Technology Performance 

Advanced Batteries Characteristics Source: DOE Energy Storage Systems Program Annual Peer Review 

FY01, Boulder City Battery Energy Storage, November 2001. 

Energy Storage System Sodium Sulfur Vanadium Redox Zinc Bromine 

Field Experience Over 30 

Projects, 25 kW 

to 6 MW, 

Largest 48 MW

Several Projects 100kW to 3 MW (pulse 

power), Largest 1.15 MWh 

Several Projects, 

50 kW to 250 kW, 

Largest 400 kWh

Production Capacity 160 MWh/yr 30 MWh/yr 40 to 70 MWh/yrActual Production 50 MWh/yr 10 MWh/yr 4.5 MWh/yr Life 15 yrs 7 to 15 yrs 10 to 20 yrs Efficiency 72% 70to 80 % 65 to 70% O&M Costs $32.5k/yr $50k/yr $30 to $150k/yr 

86
Advanced Energy Storage

Technology Description 

The U.S. electric utility industry has been 

facing new challenges with deregulation and 

limitations on installing new transmission 

and distribution equipment. Advanced storage 

technologies under active development, in 

addition to advanced batteries, include 

processes that are mechanical (flywheels), 

purely electrical (supercapacitors, super 

conducting magnetic storage), and compressedair energy storage. These advanced energystorage solutions will help achieve more 

reliable and low-cost electricity storage. 

System Concepts 

Flywheels (Low-Speed and High-Speed) 

Flywheels store kinetic energy in a rotating mass. The amount of stored energy is dependent on the speed, 

mass, and configuration of the flywheel. They have been used as short-term energy storage devices for 

propulsion applications such as engines for large road vehicles. Today, flywheel energy storage systems 

are usually categorized as either low-speed or high-speed. High-speed wheels are made of high strength, 

low-density composite materials, making these systems considerably more compact than those employing 

lower-speed metallic wheels. However, the low-speed systems are still considerably less expensive per 

kWh. 

Supercapacitors 

Supercapacitors are also known as Electric Double Layer Capacitors, pseudocapacitors, or ultracapacitors. 

Charge is stored electrostatically in polarized liquid layers between an ionically conducting electrolyte 

and a conducting electrode. Though they are electrochemical devices, no chemical reactions occur in the 

energy-storage mechanism. Since the rate of charge and discharge is determined solely by its physical 

properties, an ultracapacitor can release energy much faster (i.e., with more power) than a battery, which 

relies on slow chemical reactions. Ultracapacitors deliver up to 100 times the energy of a conventional 

capacitor and deliver 10 times the power of ordinary batteries. 

Compressed-Air Energy Storage (CAES) 

CAES systems store energy by compressing air within a reservoir using off peak/low cost electric energy. 

During charging, the plant’s generator operates in reverse – as a motor – to send air into the reservoir. 

When the plant discharges, it uses the compressed air to operate the combustion turbine generator. 

Natural gas is burned during plant discharge in the same fashion as a conventional turbine plant. 

However, during discharge, the combustion turbine in a CAES plant uses all of its mechanical energy to 

generate electricity; thus, the system is more efficient. CAES is an attractive energy-storage technology 

for large-scale storage. 

Superconducting Magnetic Energy Storage (SMES) 

SMES systems store energy in the magnetic field created by the flow of direct current in a coil of 

superconducting material. SMES systems provide rapid response to either charge or discharge, and their 

available energy is independent of their discharge rate. SMES systems have a high cycle life and, as a 

result, are suitable for applications that require constant, full cycling and a continuous mode of operation. 

SMES systems are ideal for high-power applications. Micro-SMES devices in the range of 1 to 10 MW 

are available commercially for power-quality applications. 

Flywheel Cutaway

87
Representative Technologies 

• While the system-concepts section addressed energy-storage components exclusively, all advanced 

storage systems require power conditioning and balance of plant components. 

• For vehicle applications, flywheels, CAES, and ultracapacitors are under development. 

• A dozen companies are actively developing flywheels. Steel, low-speed flywheels, are commercially 

available now; composite, high-speed flywheels are rapidly approaching commercialization. 

• Pneumatic storage (CAES) is feasible for energy storage on the order of hundreds of MWh. 

• Prototype ultracapacitors have recently become commercially available. 

Technology Applications 

• A number of industries rely upon high power quality, especially the semiconductor manufacturing and 

banking industries. Power quality losses total more than $15 billion per year in the U.S. 

Energy available in SMES is independent of its discharge rating, which makes it very attractive for high 

power and short time burst applications such as power quality. 

• SMES are also useful in transmission enhancement as they can provide line stability, voltage and 

frequency regulation, as well as phase angle control. 

• Flywheels are primarily used in transportation, defense, and power quality applications. 

• Load management is another area where advanced energy-storage systems are used (e.g., CAES). 

Energy stored during off-peak hours is discharged at peak hours, achieving savings in peak energy, 

demand charges, and a more uniform load. 

• Load management also enables the deferral of equipment upgrades required to meet an expanding 

load base which typically only overloads equipment for a few hours a day. 

• Ultracapacitors are used in consumer electronics, power quality, transportation, and defense 

and have potential applications in combination with distributed generation equipment for 

following rapid load changes. 

Current Status 

• Utilities require high reliability, and per-kilowatt costs less than or equal to those of new power 

generation ($400–$600/kW). Compressed gas energy storage can cost as little as $1–$5/kWh. SMES has 

targets of $150/kW and $275/kWh. Batteries cost between $300 and $2,000 per kWh. Vehicles require 

storage costs of $300 to $1,000/kWh to achieve significant market penetration. The major hurdle for all 

storage technologies is cost reduction. 

• Ultracapacitor development needs improved energy density from the current 1.9 W-h/kg for light-duty 

hybrid vehicles. 

Efficiencies for these technologies are 70% for compressed gas, 70-84% for batteries, and 90+% for 

flywheels and SMES. 

• Low-speed (7,000-9,000 rpm) steel flywheels are commercially available for power quality and UPS 

applications. 

• There is one 110-MW CAES facility operated by an electric co-op in Alabama. One CAES facility is 

in operation in Germany. 

• Nine SMES units have been installed in Wisconsin to stabilize a ring transmission system. 

Representative Current Manufacturers 

Flywheels Supercapacitors CAES SMES 

Active Power 

American 

Flywheel Systems 

Pillar 

Nanolab 

Cooper Maxwell 

NEC 

Ingersoll Rand 

ABB 

Dresser-Rand 

Alstrom 

American 

Superconductor 

88
Technology Future 

• Developments in the vehicular systems will most likely crossover into the stationary market. 

• High-temperature (liquid-nitrogen temperatures) superconductors that are manufacturable and can 

carry high currents could reduce both capital and operating costs for SMES. 

• High-speed flywheels need further development of fail-safe designs and/or lightweight containment. 

Magnetic bearings will reduce parasitic loads and make flywheels attractive for small uninterruptible 

power supplies and small energy management applications. 

• Much of the R&D in advanced energy storage is being pursued outside the United States, in Europe, 

and Japan. U.S. government research funds have been very low, relative to industry investments. One 

exception has been the Defense Advanced Research Programs Agency, with its flywheel containment 

development effort with U.S. flywheel manufacturers, funded at $2 million annually. The total DOE 

Energy Storage Program budget hovers in the $4 million to $6 million range during the past 10 years. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

89
Advanced Energy Storage

Market Data 

Market Predictions Source: Sandia National Laboratories, Cost Analysis of  Energy-Storage Systems for Electric Utility Applications, February 1997. 

Energy-Storage System Present Cost Projected Cost Reduction 

SMES $54,000/MJ 5-10% 

Flywheels $200/kWh 443 

Technology Performance 

Energy-Storage Costs and Efficiencies 

Source: Sandia National Laboratories, Characteristics and Technologies for Long- vs. Short-Term Energy Storage, March 2001. 

Energy-Storage System Energy-Related 

Cost ($/kWh) 

Power Related Cost ($/kW) Balance of 

Plant ($/kWh)

Discharge 

Efficiency 

Micro-SMES 72,000 300 10,000 0.95 Mid-SMES 2,000 300 1,500 0.95 SMES 500 300 100 0.95 Flywheels (high-speed) 25,000 350 1,000 0.93 Flywheels (low-speed) 300 280 80 0.9 Ultracapacitors 82,000 300 10,000 0.95 CAES 3 425 50 0.79 

90
Technology Performance 

Energy-Storage Technology Profiles 

Source: DOE/EPRI, Renewable Energy Technology Characterizations, EPRI TR-10949

Technology Installed U.S. Total Facility Size Range Potentia

Flywheels 1-2 demo facilities, no commercial sites. In 2002, 

steel flywheels with rotational speeds of 7000-9000 rpm are commercially available for power quality and UPS applications. 

kW scale Electricity 

Transpor

SMES 5 facilities with approx. 30 MW in 5 states From 1-10 MW (microSMES) to 10-100 MW Electricity 

Quality) 

Ultracapacitors Millions of units for standby power; 1 defense 

unit 

7-10 W commercial 10-20 kW prototype 

TransporConsumeElectricity 

CAES 110 MW in Alabama 25 MW to 350 MW Electricity 

Spinning 

91
92
Superconducting Power Technology

Technology Description 

Superconducting power technology refers to electric 

power equipment and devices that use 

superconducting wires and coils. High Temperature 

Superconductivity (HTS) enables electricity 

generation, delivery, and end use without the 

resistance losses encountered in conventional wires 

made from copper or aluminum. HTS wires 

currently carry 3 to 5 times the power, without the 

resistance losses of comparable diameter copper 

wires. HTS power equipment, such as motors, 

generators, and transformers, has the potential to be 

half the size and weight of conventional alternatives 

with the same power rating and only half the energy 

losses. 

System Concepts 

• HTS systems will be smaller, more efficient, and carry more power than a similarly rated 

conventional system. 

• HTS systems will help the transmission and distribution system by allowing for greater power 

transfer capability, increased flexibility, and increased power reliability. 

Representative Technologies 

Transmission Cables 

Motors 

Generators 

Current Limiters 

Transformers 

Flywheel Electricity Systems 

Technology Applications 

• Superconducting technology will modernize the electric grid and infrastructure, resulting in greater 

flexibility, efficiency, and cost effectiveness. 

• Wire and Coils have reached a sufficient level of development to allow for their introduction into 

prototype applications of HTS systems such as motors, generators, transmission cables, current 

limiters, and transformers. 

• Motors rated greater than 1,000 hp will primarily be used for pump and fan drives for utility and 

industrial markets. 

• Current controllers will perform as a fast sub-cycle breaker when installed at strategic locations in 

the transmission and distribution system. 

• Flywheel electricity systems can be applied to increase electric-utility efficiency in two areas—

electric-load leveling and uninterruptible power systems (UPS) applications. 

• Transformers are environmentally friendly and oil-free, making them particularly useful where 

transformers previously could not be sited, such as in high-density urban areas or inside buildings. 

• Reciprocating Magnetic Separators can be used in the industrial processing of ores, waste solids, 

and waste gases, as well as performing isotope separations and water treatment. 

 Source: American Superconductor

93
Current Status 

• Much of the research and development in HTS is focused on wire and system development and 

prototype system design and deployment. 

• There are 18 manufacturers, eight National Laboratories, six utilities, and 17 universities 

participating in the U.S. Department of Energy Superconductivity Program alone. The list of 

manufacturers includes: 

3M 

American Superconductor 

IGC SuperPower 

Southwire Company 

ABB 

Pirelli Cables North America 

Waukesha Electric Systems 

• Prototype power transmission cables have been developed and are being tested by two teams led by 

Pirelli Cable Company and Southwire Company respectively. 

• A 1,000-horsepower prototype motor was produced and tested by Rockwell Automation/Reliance 

Electric Company. The results of these tests are being used to design a 5,000 hp motor. 

• A team led by General Electric has developed a design for a 100 MW generator. 

• A 15 kV current controller was tested at a Southern California Edison substation in July 1999. 

• The design of a 3 kW/10 kWh flywheel system has been completed. The superconducting bearings, 

motor/generator, and control system have been constructed and are undergoing extensive testing. A 

rotor construction is underway. 

• The design of the reciprocating magnetic separator has been finalized, and components for the 

system have been procured and assembled. The test site has been prepared, and cryogenic testing 

has begun. 

• Use of HTS lines results in a 30% reduction in total losses. Total ownership costs are about 20% 

lower than traditional lines. HTS lines are nonflammable and do not contain oil or any other 

pollutant. 

Technology History 

• In 1911, after technology allowed liquid helium to be produced, Dutch physicist Heike 

Kammerlingh Onnes found that at 4.2 K, the electrical resistance of mercury decreased to almost 

zero. This marked the first discovery of superconducting materials. 

• Until 1986, superconductivity applications were highly limited due to the high cost of cooling to 

such low temperatures, which resulted in costs higher than the benefits of using the new 

technology. 

• In 1986, two IBM scientists, J. George Bednorz and Karl Müller achieved superconductivity on 

lanthanum copper oxides doped with barium or strontium at temperatures as high as 38 K. 

• In 1987, the compound Y1Ba2Cu3O7 (YBCO) was given considerable attention, as it possessed the 

highest critical temperature at that time, at 93 K. In the following years, other copper oxide 

variations were found, such as bismuth lead strontium calcium copper oxide (110 K), and thallium 

barium calcium copper oxide (125 K). 

• In 1990, the first (dc) HTS motor was demonstrated. 

• In 1992, a 1-meter-long HTS cable was demonstrated. 

• By 1996, a 200-horsepower HTS motor was tested and exceeded its design goals by 60%. 

• A Pirelli Cable team installed a 120m HTS cable in Detroit, Michigan under the DOE 

Superconductivity Partnership Initiative. Since February 2000, Southwire’s 30m prototype cable 

has been powering three manufacturing plants in Carrollton, Georgia. 

• The first HTS cable, worldwide, to power industrial plants exceeded 13,000 hours of trouble-free 

service recently. The 30m cable was installed in Carrollton, Georgia, in June 2001. The cable has 

been unattended since then. 

94
• HTS transformers have seen increased interest, as Waukesha Electric Systems demonstrated a 1-

MVA prototype transformer in 1999. This team is also leading the development of a 5/10-MVA, 

26.4-kV/4.2-kV three-phase prototype. 

• A 750 kW HTS motor was demonstrated by Rockwell Automation in 2000. This team is now 

designing a motor with five times the rating. 

Technology Future

Year of 50% Market Penetration 

Motors Transformers Generators Underground Cable 

2018 2015 2019 2013 

Source: ORNL - High Temperature Superconductivity: The Products and Their Benefits, 2002 Edition, Table ES-1. 

• Low-cost, high-performance YBCO Coated Conductors will be available in 2005 in kilometer 

lengths. 

• HTS wires will have 100 times the capacity of conventional wires. 

• Payback periods will be within 2-5 years of operation. 

• The present cost of BSCCO type HTS wire is $200/kA-m. By 2005, for applications in liquid 

nitrogen, the wire cost will be less than $50/kA-m; and for applications requiring cooling to 

temperatures of 20-60 K, the cost will be less than $30/kA-m. 

By 2010, the cost-performance ratio will have improved by at least a factor of four. The cost target is 

$10/kA-m. 

Source: National Renewable Energy Laboratory. U.S. Climate Change Technology Program. 

Technology Options: For the Near and Long Term. DOE/PI-0002. November 2003.

95
Superconducting Power Technology 

Market Data 

Projected Market for HTS devices 

Source: Oak Ridge National Laboratory - High Temperature Superconduc

Their Benefits, 2002 Edition, Total Market Benefits, p 40. 

(Thousands of Dollars) 

2004 2006 2008 2010 2012 2014 

Motors 0 0 27.29 169.24 527.03 1310.49 31Transformers 0 3.8 14.22 37.47 90.63 197.73 3Generators 0 0 0 4.09 15.56 41.12 1Cables 0 0.17 0.59 1.44 2.81 4.86 Total 0 3.97 42.1 212.24 636.03 1554.2 3The report assumes electrical generation and equipment market growth averaging 2.5% per year through 2020. This numbhistoric figures (the past fifteen years) and the assumption that electric demand will drive electric supply. Underground Power Cables: Market Penetration and Benefits 

Source: Oak Ridge National Laboratory - High Temperature Superconduc

Their Benefits, 2002 Edition, Total Market Benefits, p 40. 

2004 2006 2008 2010 2012 2014 

% Market 0 6.7 15 27 40 56 Miles Sold this Year 0 13.89 32.68 61.77 96.19 141.47 1Total Miles Installed 0 20.76 74.69 183.34 356.96 616.74 9Total Annual Savings (106 $) 0 0.17 0.59 1.44 2.81 4.86 

96
Technology Performance 

HTS Energy Savings 

Source: Oak Ridge National Laboratory - High Temperature Superconduc

Their Benefits, 2002 Edition, Tables M-2, T-1, G-1, C-2 

(GWh) 

2004 2006 2008 2010 2012 2014 

Motors 0 0 0.4 3 8 21 Transformers 0 0.1 0.2 1 1 3 Generators 0 0 0 0.1 0.2 1 Cables 0 3 18 56 133 270 Total 0 4 19 60 143 294 

97
98
Thermally Activated Technologies

Technology Description 

Thermally Activated Technologies (TATs), such as heat 

pumps, absorption chillers, and desiccant units, provide 

on-site space conditioning and water heating, which 

greatly reduce the electric load of a residential or 

commercial facility. These technologies can greatly 

contribute to system reliability.

System Concepts 

• TATs may be powered by natural gas, fuel oil, 

propane, or biogas, avoiding substantial energy conversion 

losses associated with electric power transmission, 

distribution, and generation. 

• These technologies may use the waste heat from onsite power generation and provide total energy solutions 

for onsite cooling, heating, and power. 

Representative Technologies 

• Thermally activated heat pumps can revolutionize the way residential and commercial buildings are 

heated and cooled. This technology enables highly efficient heat pump cycles to replace the best natural 

gas furnaces, reducing energy use as much as 50%. Heat pumps take in heat at a lower temperature and 

release it a higher one, with a reversing valve that allows the heat pump to provide space heating or 

cooling as necessary. In the heating mode, heat is taken from outside air when the refrigerant 

evaporates and is delivered to the building interior when it condenses. In the cooling mode, the function 

of the two heat-exchanger coils is reversed, so heat moves inside to outside. 

• Absorption chillers provide cooling to buildings by using heat. Unlike conventional electric 

chillers, which use mechanical energy in a vapor-compression process to provide refrigeration, 

absorption chillers primarily use heat energy with limited mechanical energy for pumping. The chiller 

transfers thermal energy from the heat source to the heat sink through an absorbent fluid and a 

refrigerant. The chiller achieves its refrigerative effect by absorbing and then releasing water vapor into 

and out of a lithium bromide solution. In the process, heat is applied at the generator and water vapor is 

driven off to a condenser. The cooled water vapor then passes through an expansion valve, reducing the 

pressure. The low-pressure water vapor then enters an evaporator, where ambient heat is added from a 

load and the actual cooling takes place. The heated, low-pressure vapor returns to the absorber, where it 

recombines with lithium bromide and becomes a low-pressure liquid. This low-pressure solution is 

pumped to a higher pressure and into the generator to repeat the process. 

• Desiccant equipment is useful for mitigation of indoor air-quality problems and for improved 

humidity control in buildings. The desiccant is usually formed in a wheel made up of lightweight 

honeycomb or corrugated material (see figure). Commercially available desiccants include silica gel, 

activated alumina, natural and synthetic zeolites, lithium chloride, and synthetic polymers. The wheel is 

rotated through supply air, usually from the outside, and the material naturally attracts the moisture 

from the air before it is routed to the building. The desiccant is then regenerated using thermal energy 

from natural gas, the sun, or waste heat. 

99
Technology Applications 

• Thermally activated heat pumps are a new generation of advanced absorption cycle heat pumps that 

can efficiently condition residential and commercial space. Different heat pumps will be best suited for 

different applications. For example, the GAX heat pump is targeted for northern states because of its 

superior heating performance; and the Hi-Cool heat pump targets the South, where cooling is a priority. 

• Absorption chillers can change a building’s thermal and electric profile by shifting the cooling from 

an electric load to a thermal load. This shift can be very important for facilities with time-of-day 

electrical rates, high cooling-season rates, and high demand charges. Facilities with high thermal loads, 

such as data centers, grocery stores, and casinos, are promising markets for absorption chillers. 

• Desiccant technology can either supplement a conventional air-conditioning system or act as a 

standalone operation. A desiccant can remove moisture, odors, and pollutants for a healthier and more 

comfortable indoor environment. Facilities with stringent indoor air-quality needs (schools, hospitals, 

grocery stores, hotels) have adapted desiccant technology. 

• CHP applications are well suited for TATs. They offer a source of “free” fuel in the form of waste 

heat that can power heat pumps and absorption chillers, and regenerate desiccant units. 

Current Status 

Thermally activated heat pump technology can replace the best natural gas furnace and reduce energy 

use by as much as 50%, while also providing gas-fired technology. 

Desiccant technology may be used in pharmaceutical manufacturing to extend the shelf life of 

products; refrigerated warehouses to prevent water vapor from forming on the walls, floors, and 

ceilings; operating rooms to remove moisture form the air, keeping duct work and sterile surfaces dry; 

and hotels, to prevent buildup of mold and mildew. 

Companies that manufacture TAT equipment include: 

York International 

Trane 

Munters Corporation 

Kathabar Systems 

Broad 

Air Technology Systems 

American Power Conversion Company 

Goettl 

Technology History 

• In the 1930s, the concept of dehumidifying air by scrubbing it with lithium chloride was 

introduced, paving the way for development of the first desiccant unit. 

• In 1970, Trane introduced a mass-produced, steam-fired, double-effect LiBr/H2O absorption chiller. 

• In 1987, the National Appliance Energy Conversion Act instituted minimum efficiency standards 

for central air-conditioners and heat pumps. 

Technology Future

• Expand the residential market of the second-generation Hi-Cool residential absorption heat pump 

technology to include markets in southern states; the targeted 30% improvement in cooling 

performance can only be achieved with major new advancements in absorption technology or with an 

engine-driven system. 

• Work in parallel with the first-generation GAX effort to determine the most attractive secondgeneration Hi-Cool technology. 

• Fabricate and test the 8-ton advanced cycle VX GAX ammonia/water heat pump. 

• Fabricate and test the 3-ton complex compound heat pump and chiller. 

• Develop, test, and market an advanced Double Condenser Coupled commercial chiller, which is 

expected to be 50% more efficient than conventional chillers. 

• Assess new equipment designs and concepts for desiccants using diagnostic techniques, such as 

infrared thermal performance mapping and advanced tracer gas-leak detection. 

100
3.1 – States with Competitive Electricity Markets 

Purple-colored states are active in the restructuring process, and these states have either 

enacted enabling legislation or issued a regulatory order to implement retail access. Retail 

access is either currently available to all or some customers, or will soon be available. Those 

states are Arizona, Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, 

Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, 

Pennsylvania, Rhode Island, Texas, and Virginia. In Oregon, no customers are currently 

participating in the state's retail access program, but the law allows access to nonresidential 

customers.

A green-colored state signifies a delay in the restructuring process or the implementation of 

retail access. Those states are Arkansas, Montana, Nevada, New Mexico, and Oklahoma. 

California is the only blue-colored state because direct retail access has been suspended. 

Source: U.S. DOE, Energy Information Administration 

http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html, last updated February 2003. 

Figure 3.1.1. Status of Restructuring of State Electricity Markets 

101
3.2 – States with System Benefit Charges (SBC) 

A System Benefit Charge (SBC) is a small fee added to a customer’s electricity bill used to 

fund programs that benefit the public, such as low-income energy assistance, energyefficiency, and renewable energy. There are 15 states with SBCs, through which a portion of 

the money will be used to support renewable resources. Together, these states will collect 

about $4 billion in funds to support renewable resources between 1998 and 2017. 

Source: Union of Concerned Scientists, June 2004 

Figure 3.2.1. State System Benefit Funds 

Source: Bolinger, M., R. Wiser, L. Milford, M. Stoddard, and K. Porter. Clean Energy Funds: An Overview of 

State Support for Renewable Energy, Lawrence Berkeley Laboratory, April 2001. 

Figure 3.2.2. Aggregation Annual and Cumulative State Funding 

0

50

100

150

200

250

300

350

400

19981999200020012002200320042005200620072008200920102011

Million US$

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Billion US$

Annual, all states (left scale)

Cumulative (right scale)

Cumulative 1998-2017

$114 

mil

RI: $30 mil

MA: $494 mil

CT: $248 mil

NJ: $286 mil.

$89 mil

$67 mil.

$21 mil

$200 mil

$2,048 mil

$95 mil.

$14 mil

$234 mil. • 15 state funds = $4 

billion by 2017

DE: $18 mil.

$25 mil.

102
Source: Union of Concerned Scientists, June 2004 

Figure 3.2.3. The Future Impact of State Purchase Mandates and Renewable Energy 

Funds 

Table 3.2.1. Renewable Energy Funding Levels and Program Duration 

State 

Approximate Annual 

Funding 

($ Million) 

$ Per-Capita 

Annual 

Funding 

$ Per-MWh 

Funding 

Funding Duration 

CA 135 4.0 0.58 1998 - 2012 

CT 15 Æ 30 4.4 0.50 2000 - indefinite 

DE 1 (maximum) 1.3 0.09 10/1999 - indefinite 

IL 5 0.4 0.04 1998 - 2007 

MA 30Æ20 4.7 0.59 1998 - indefinite 

MN 9 N/A N/A 2000 - indefinite 

MT 2 2.2 0.20 1999 - 7/2003 

NJ 30 3.6 0.43 2001 - 2008 

NM 4 2.2 0.22 2007 - indefinite 

NY 6 Æ 14 0.7 0.11 7/1998 - 6/2006 

OH 15 Æ 5 (portion of) 1.3 0.09 2001 - 2010 

OR 8.6 2.5 0.17 10/2001 - 9/2010 

PA 10.8 (portion of) 0.9 0.08 1999 - indefinite 

RI 2 1.9 0.28 1997 - 2003 

WI 1 Æ 4.8 0.9 0.07 4/1999 - indefinite 

Note: Annual and per-MWh funding are based on funds expected in 2001. 

Source: Bolinger et al., 2001

0

5,000

10,000

15,000

20,000

25,000

20002001

200220032004

2005

200620072008

2009

201020112012

2013

201420152016

2017

Megawatts

*Does not include Maryland or Hawaii.

**Includes Illinois, Montana, Oregon, Pennsylvania and Rhode Island (Fund only).

Other**

California

Nevada

IA & WI

New Jersey

Connecticut

MA

Maine

Minnesota

AZ & NM

New York

Texas

17,310 MW new renewables

12.8 MMTCE reductions

CO2 reduction equivalent to

* 2.3 billion more trees

* 7.0 million less cars

103
Table 3.2.2. State SBC Funding of Large-Scale Renewable Projects 

State Form of Funding 

Distribution 

Level of 

Funding 

($ Million) 

Results1

Discounted 

cents/kWh 

Incentive 

over Five 

Years2

CA Five-year production 

incentive 

162 

 40 

 40 

543 MW (assorted) 

471 MW (assorted) 

300 MW (assorted) 

1.20 

0.59 

0.75 

IL Grant 0.55 

1 

0.352 

0.55 

3 MW landfill gas 

3 MW hydro 

1.2 MW hydro 

15 MW landfill gas 

0.57 

1.86 

1.63 

0.11 

MT Three-year production 

incentive 

1.5 3 MW wind 3.63 

NY Grants with performance 

guarantees 

9 

4 

51.5 MW wind 

6.6 MW wind 

1.95 

6.75 

PA Grant/ production incentive 6 67 MW wind 1.00 

1

 Results are projected and are based on announced results of solicitations. 

2 Incentives have been normalized to their five-year production incentive equivalent using a 10% discount 

rate. 

Source: Bolinger et al., 2001. 

 

104
3.3 – States with Renewable Portfolio Standards (RPS) 

A Renewable Portfolio Standard (RPS) is a policy that obligates a retail electricity supplier to 

include renewable resources in its electricity generation portfolio. Retail suppliers can meet 

the obligation by constructing or owning eligible renewable resources or purchasing the 

power from eligible generators. To date, 16 states have adopted RPS policies or renewable 

purchase obligations. Initially, most states adopted RPS policies as part of electric industry 

restructuring; but, more recently, a number of states have implemented policies by legislation 

or proceedings that are separate from restructuring activities. In conjunction with system 

benefits funds, RPS policies are expected to lead to the development of more than 17,000 

MW of new renewable energy capacity by 2017 (see Figure 3.3.1). 

Source: Updated by NREL July 2004 based on original map prepared by Lawrence Berkeley National Laboratory 

and Union of Concerned Scientists. 

Figure 3.3.1. Renewable Portfolio Standards and Renewables Purchase Obligations 

by State 

WI: 2.2% by 2011

NV: 15% by 2013

TX: 2880 MW by 2009

PA: varies by utility

NJ: 6.5% by 2008

CT: 10% by 2010

MA: 4% new by 2009

ME: 30% by 2000

NM: 10% by 2011

AZ: 1.1% by 2007 

CA: 20% by 2017

MN: 1235 MW by 2010

IA: 105aMW

MD: 7.5% by 2019

HI: 20% by 2020

RI: 16% by 2019

105
Table 3.3.1. State Renewable Portfolio Standards and Purchase Requirements 

State Purchase 

Requirements 

Eligible Resources Credit 

Trading 

Penalties Outside of 

state? 

AZ 0.2% in 2001, rising 

by 0.2%/yr to 

1% in 2005, then to 

1.05% in 2006, and 

to 1.1% from 

2007-2012. 

(2001: 50% from 

solar electric, 

2004:60% from 

solar electric) 

PV and solar thermal 

electric, R&D, solar hot 

water, and in-state landfill 

gas, wind, and biomass. 

No central 

credit trading 

system 

30 cents/kWh 

starting in 2004. 

Proceeds go to 

solar electric 

fund to finance 

solar projects. 

Out-of-state 

solar eligible 

if power 

reaches AZ. 

Landfill gas, 

wind, and 

biomass 

must be instate. 

CA Investor-owned 

utilities must add 

minimum 1% 

annually to 20% by 

2017. 

Biomass, solar thermal, 

photovoltaic, wind, 

geothermal, existing 

hydro 

< 30MW, fuel cells using 

renewable fuels, digester 

gas, landfill gas, ocean 

energy. 

WREGIS 

system under 

development 

To be 

determined 

Out-of-state 

eligible if 

meets criteria 

for approval. 

CT 3% Class I or II 

Technologies by 

Jan 1, 2004 

Class I 1% Jan 1, 

2004 increasing to 

1.5% by 2005, 2% 

by 2006, 3.5% by 

2007, 5% by 2008, 

6% by 2009, and 

7% by Jan 1, 2010 

Class I: solar, wind, new 

sustainable biomass, 

landfill gas, fuel cells, 

ocean thermal, wave, 

tidal, advanced 

renewable energy 

conversion technologies, 

new run of river hydro (<5 

MW). 

Class II: licensed hydro, 

MSW, and other biomass.

Yes. Using 

NEPOOL 

Generation 

Information 

System. 

Penalty of 

5.5¢/kWh paid to 

the Renewable 

Energy 

Investment Fund 

for the 

development of 

Class I 

renewables 

New England 

resources or 

electricity 

delivered to 

New England 

are eligible. 

IA Investor-owned 

utilities to purchase 

105 average MW 

(~2% of 1999 

sales) 

Solar, wind, methane 

recovery, and biomass 

No Unspecified Out-of-state 

renewables 

not eligible. 

HI 8% by end of 2005, 

10% by 2010, 15% 

by 2015 and 20% 

by 2020 

Wind, solar, hydropower, 

biomass including landfill 

gas, waste to energy, and 

fuels derived from organic 

sources, geothermal, 

ocean energy, fuel cells 

using hydrogen from 

renewables 

Unspecified Unspecified; 

standard to be 

revisited if 

utilities can not 

meet it in costeffective manner 

Unspecified 

ME 30% of retail sales 

in 2000 and 

thereafter. PUC will 

revisit within 5 

years. 

Fuel cells, tidal, solar, 

wind, geothermal, hydro, 

biomass, and MSW (< 

100MW); high efficiency 

cogeneration. Selfgeneration is not eligible. 

Resource supply under 

this definition exceeds 

RPS requirement. 

No. However, 

PUC is 

considering 

adoption of 

NEPOOL 

Generation 

Information 

System. 

Possible 

sanctions at 

discretion of 

PUC including 

license 

revocation, 

monetary 

penalties, or 

payment into 

renewables fund. 

New England 

resources or 

electricity 

delivered to 

New England 

are eligible. 

106
State Purchase 

Requirements 

Eligible Resources Credit 

Trading 

Penalties Outside of 

state? 

MD 3.5% by 2006 with 

1% from Tier 1 

sources, Tier 1 

increasing by 1% 

every other year 

from 2007 to 2018, 

Tier II remains at 

2.5%, 7.5% total by 

2019 and in 

subsequent years 

Tier 1: solar, wind, 

geothermal, qualifying 

biomass, small 

hydropower (<30MW), 

and landfill methane 

Tier II: existing large 

hydropower, poultry litter 

incineration, existing 

waste to energy 

Yes Alternative 

Compliance fee 

of 2¢/kWh for 

Tier 1 and 

1.5¢/kWh for Tier 

2 paid to 

Maryland 

Renewable 

Energy Fund 

Trading 

system to 

work in 

conjunction 

with PJM 

system 

MA 1% of sales to enduse customers from 

new renewables in 

2003, +0.5%/yr to 

4% in 2009 

1%/yr increase 

thereafter until 

determined by 

Division of Energy 

Resources 

New renewables placed 

into commercial operation 

after 1997, including 

solar, wind, ocean 

thermal, wave, tidal, fuel 

cells using renewable 

fuels, landfill gas, and 

low-emission advanced 

biomass. Excess 

production from existing 

generators over historical 

baseline eligible. 

Yes. Using 

NEPOOL 

Generation 

Information 

System. 

Entities may 

comply by 

paying 5¢/kWh. 

Non-complying 

retailers must 

submit a 

compliance plan. 

Revocation or 

suspension of 

license is 

possible. 

New England 

resources or 

electricity 

delivered to 

New England 

are eligible. 

MN (Not true RPS) 

Applies to Xcel 

Energy only: 425 

MW wind by 2002 

and 110 MW 

biomass. 

Additional 400 MW 

wind by 2006 and 

300 MW by 2010 

Wind, biomass. No, other 

than standard 

regulatory 

oversight. 

No Unspecified 

NV 5% by 2003 

increase 

2%/yr until 

15% in 2013. 

Minimum 5%/yr 

must come from 

solar. 

Solar, wind, geothermal, 

& biomass (includes 

agricultural waste, wood, 

MSW, animal waste and 

aquatic plants). 

Distributed resources 

receives extra credit 

(1.15). 

Yes. RECs 

valid for 4 

years 

following year 

issued. 

Financial 

penalties may be 

applied for 

noncompliance. 

Out-of-state 

resources 

eligible with 

dedicated 

transmission 

line. 

NJ Class I or II: 2.5% 

Class I: 4% by 

2008, with solar 

requirement of 

0.16% retail sales 

(90MW) 

Class I.: Solar, PV, wind, 

fuel cells, geothermal, 

wave, tidal, landfill 

methane, and sustainable 

biomass. 

Class II: hydro <30 MW 

and MSW facilities that 

meet air pollution 

requirements. 

Legislation 

allows credit 

trading, PJM 

credit trading 

system under 

development. 

Shortfalls must 

be made up in 

the following 

year or financial 

penalties, license 

revocation or 

suspension. 

Eligible if 

power flows 

into PJM or 

NYISO. 

Class II must 

come from 

states open 

to retail 

competition. 

107
State Purchase 

Requirements 

Eligible Resources Credit 

Trading 

Penalties Outside of 

state? 

NM 5% of retail sales 

by 2006. Increase 

by 1%/yr to 10% by 

January 1, 2011 

and thereafter. 

Solar, wind, hydro (<=5 

MW), biomass, 

geothermal, and fuel 

cells. 1 kWh solar = 

3kWh; 1 kWh biomass, 

geothermal, landfill gas, 

or fuel cells =2 kWh 

toward compliance 

Yes. RECs 

valid for 4 

years from 

date of 

issuance. 

Yes, but to be 

determined. 

Must be 

delivered in 

state. 

PA For PECO, West 

Penn, & PP&L, 

20% of residential 

consumers served 

by competitive 

default provider: 

2% in 2001 rising 

0.5%/yr. For GPU 

0.2% in 2001 for 

20% customers, 

40% of customers 

in 2002, 60% in 

2003, 80% in 2004. 

Solar, wind, ocean, 

geothermal, sustainable 

biomass. 

No. Unspecified. Eligible 

RI 3% by 2003, 

increasing 0.5% 

annually 2008-

2010, increasing 

1% annually 2011-

2014, increasing 

1.5% annually 

2015-2019 

Solar, wind, eligible 

biomass, including cofiring, geothermal, small 

hydropower, ocean, fuel 

cells using hydrogen 

derived from renewables. 

 

Yes. Using 

NEPOOL 

Generation 

Information 

System. 

Alternative 

compliance 

payments can 

be made to 

Renewable 

Energy 

Development 

Fund. 

New England 

resources or 

electricity 

delivered to 

New England 

are eligible.

TX 1280 MW by 2003 

increase to 2880 

MW by 2009 (880 

MW from existing) 

~2.3% of 2009 

sales. 

Solar, wind, geothermal, 

hydro, wave, tidal, 

biomass, including landfill 

gas. New (operational 

after Sept. 1, 1999) or 

small (<2MW) facilities 

eligible. 

Yes. Lesser of 

5¢/kWh or 

200% of 

average market 

value of 

renewable 

energy credits. 

Under certain 

circumstances, 

penalty may not 

be assessed. 

Not eligible 

unless 

dedicated 

transmission 

line into 

state. 

WI 0.5% by 2001 

increasing to 2.2% 

by 2011 (0.6% can 

come from facilities 

installed prior to 

1998). 

Wind, solar, biomass, 

geothermal, tidal, fuel 

cells that use renewable 

fuel, & hydro under 60 

MW. Eligibility may be 

extended by PUC. 

Yes. Utilities 

with excess 

RECs can 

trade or bank 

them. 

Penalty of 

$5,000-

$500,000 is 

allowed in 

legislation. 

Eligible 

Source: Table updated by NREL July 2004. Derived from table in Wiser, R. Porter, K., Grace, R., Kappel, C. Creating 

Geothermal Markets: Evaluating Experience with State Renewables Portfolio Standards, report prepared for the 

National Geothermal Collaborative, 2003. 

108
Table 3.3.2. State Renewable Energy Goals (Nonbinding) 

State Purchase Requirements Eligible Resources 

Illinois 5% by 2010; 15% in 2020 Wind, solar thermal, PV, organic waste 

biomass, & existing run-of-river hydro. 

Minnesota 1% by 2005 increasing by at least 

1%/year to 10% by 2015 

Wind, solar, hydro (<60 MW), and biomass 

109
3.4 – States with Net-Metering Policies 

Net metering allows customers with generating facilities to turn their electric meters 

backward when their systems are producing energy in excess of their on-site demand. In this 

way, net metering enables customers to use their own generation to offset their consumption 

over a billing period. This offset means that customers receive retail prices for the excess 

electricity they generate. Without net metering, a second meter is usually installed to measure 

the electricity that flows back to the provider, with the provider purchasing the power at a rate 

much lower than the retail rate. 

Source: J. Green, National Renewable Energy Laboratory, updated July 2004. 

http://www.eere.energy.gov/greenpower/resources/maps/netmetering_map.shtml 

Figure 3.4.1. Net-Metering Policies by State

None

Individual Utilities

Investor-Owned Utilities Only, Not Rural Cooperatives

Investor-Owned Utilities and Rural Cooperatives

None

Individual Utilities

Investor-Owned Utilities Only, Not Rural Cooperatives

Investor-Owned Utilities and Rural Cooperatives

Net Metering By State

Revised: 9Jul04

10 kW 

50 kW

1 MW

100 kW

No Limit

100 kW

10 kW

100 kW,

25,000

kWh/y

40 kW

20 kW

25/100 kW

1,000 

kWh/

mo

60 kW

30 kW

10/400 kW

PV Only

25 kW 15/150 kW

25 kW

10/500

kW

50 kW

25 kW

No

Limit

25 kW

100 kW

100 kW

25 kW

80 kW

Solar Only

40 kW

10 kW

Monthly Net Metering

Annual Net Metering

Varies by Utility or Unknown

25 kW

25/100

kW

10/100

kW

50 kW

25 kW

10/25 kW

PV

Only

25/

100 kW

20 

kW

110
Table 3.4.1. Summary of State Net-Metering Policies 

State Allowable 

Technology 

and Size 

Allowable 

Customer 

Statewide

Limit 

Treatment of 

Net Excess 

Generation (NEG)

Authority Enacted Scope of 

Program 

AZ ≤10 kW; 

eligible 

technologies 

vary by utility 

All customer 

classes 

None Annual NEG 

granted to utility 

ACC; Utility 

Tariffs 

1981 SRP and 

TEP 

AR Renewables, 

fuel cells and 

microturbines 

≤25 kW 

residential 

≤100 kW 

commercial 

All customer 

classes 

None Monthly NEG 

granted to utilities 

Legislature 2001 All utilities 

CA Solar and wind

≤1000 kW 

All customer 

classes 

0.5% of 

utilities peak 

demand 

Annual NEG 

granted to utilities 

Legislature 2002; 

2001; 

1995 

All utilities 

CO Wind and PV 

3 kW, 10 kW 

Varies NA Varies Utility tariffs 1997 Four 

Colorado 

utilities 

CT Renewables 

and fuel cells 

≤100 kW 

Residential None Not specified Legislature 1990, 

updated 

1998 

All IOUs, 

No REC in 

state. 

DE Renewables 

≤25 kW 

All customer 

classes 

None Not specified Legislature 1999 All utilities 

FL JEA: PV and 

wind ≤10 kW 

JEA: 

Residential 

only; NSB: 

All customer 

classes 

None JEA and NSB: 

Monthly NEG 

granted to 

customer 

Individual 

Utility Tariffs 

2003 

(JEA) 

JEA, New 

Smyrna 

Beach 

GA Solar, wind, 

fuel cells 

≤10 kW 

residential 

≤100 kW 

commercial 

Residential 

and 

commercial 

0.2% of 

annual peak 

demand 

Monthly NEG or 

total generation 

purchased at 

avoided cost or 

higher rate if green 

priced 

Legislature 2001 All utilities 

HI Solar, wind, 

biomass, 

hydro 

≤50 kW 

Residential 

and small 

commercial 

0.5% of 

annual peak 

demand 

Monthly NEG 

granted to utilities 

Legislature 2001 All utilities 

ID Eligible 

technologies 

vary by utility 

≤25 kW 

residential 

≤100 kW 

commercial 

(Avista ≤25 

kW) 

Residential 

and small 

commercial 

None NEG varies by 

utility 

Public Utility 

Commission 

1980 IOUs only,

RECs are 

not rateregulated 

IL Solar and wind 

≤40 kW 

All customer 

classes; 

ComEd only 

0.1% of 

annual peak 

demand 

NEG purchased at 

avoided cost 

ComEd 

tariff 

2000 Commonwealth 

Edison 

111
State Allowable 

Technology 

and Size 

Allowable 

Customer 

Statewide

Limit 

Treatment of 

Net Excess 

Generation (NEG)

Authority Enacted Scope of 

Program 

IN Renewables 

and 

cogeneration 

≤1,000 

kWh/month 

All customer 

classes 

None Monthly NEG 

granted to utilities 

Public Utility 

Commission 

1985 IOUs only,

RECs are 

not rateregulated 

IA Renewables 

and 

cogeneration 

(No limit per 

system) 

All customer 

classes 

105 MW Monthly NEG 

purchased at 

avoided cost 

Iowa Utility 

Board 

1993 IOUs only, 

RECs are 

not rateregulated 

[2] 

KY Residential PV 

≤ 15 kW 

Not specified 0.1% of a 

supplier's 

single-hour 

peak load for 

previous 

year 

Monthly NEG 

granted to 

customer 

Legislature 2004 IOUs and 

RECs 

LA Residential 

≤25 kW; ≤100 

kW 

commercial 

and farm 

Residential, 

commercial, 

farm 

None Not specified Legislature 2003 All utilities 

ME Renewables 

and fuel cells 

≤100 kW 

All customer 

classes 

None Annual NEG 

granted to utilities 

Public Utility 

Commission 

1998 All utilities 

MD Solar and wind

≤80 kW 

Residential, 

commercial, 

and nonprofit

0.2% of 

1998 peak 

Monthly NEG 

granted to utilities 

Legislature 1997 All utilities 

MA Qualifying 

facilities 

≤60 kW 

All customer 

classes 

None Monthly NEG 

purchased at 

avoided cost 

Legislature 1997 All utilities 

MN Qualifying 

facilities 

≤40 kW 

All customer 

classes 

None NEG purchased at 

utility average 

retail energy rate 

Legislature 1983 All utilities 

MT Solar, wind 

and hydro 

≤50 kW 

All customer 

classes 

None Annual NEG 

granted to utilities 

at the end of each 

calendar year. 

Legislature 1999 IOUs only 

NV Biomass, 

geothermal, 

solar, wind, 

hydro 

≤30 kW 

All customer 

classes 

None Monthly or annual 

NEG granted to 

utilities 

Legislature 2001; 

1997 

All utilities 

NH Solar, wind 

and hydro 

≤25 kW 

All 

customers 

classes 

0.05% of 

utility's 

annual peak 

NEG credited to 

next month 

Legislature 1998 All utilities 

NJ PV and wind 

≤100 kW 

Residential 

and small 

commercial 

0.1% of peak 

or $2M 

annual 

financial 

impact 

Annualized NEG 

purchased at 

avoided cost 

Legislature 1999 All utilities 

112
State 

Allowable 

Technology 

and Size 

Allowable 

Customer 

Statewide

Limit 

Treatment of 

Net Excess 

Generation (NEG)

Authority Enacted Scope of 

Program 

NM Renewables 

and 

cogeneration 

≤10 kW 

All customer 

classes 

None NEG credited to 

next month, or 

monthly NEG 

purchased at 

avoided cost (utility 

choice) 

Public Utility 

Commission 

1999 All utilities 

NY Solar 

residential ≤10 

kW; wind 

residential ≤

25 kW; Farm 

biogas 

systems <400 

kW; Farm wind 

≤ 125 kW 

Residential; 

farm 

systems 

0.1% 1996 

peak 

demand 

Annualized NEG 

purchased at 

avoided cost 

Legislature 2002; 

1997 

All utilities 

ND Renewables 

and 

cogeneration 

≤100 kW 

All customer 

classes 

None Monthly NEG 

purchased at 

avoided cost 

Public Utility 

Commission 

1991 IOUs only,

RECs are 

not rateregulated 

OH Renewables, 

microturbines, 

and fuel cells 

(no limit per 

system) 

All customer 

classes 

1.0% of 

aggregate 

customer 

demand 

NEG credited to 

next month 

Legislature 1999 All utilities 

OK Renewables 

and 

cogeneration 

≤100 kW and 

≤25,000 

kWh/year 

All customer 

classes 

None Monthly NEG 

granted to utility 

Oklahoma 

Corporation 

Commission 

1988 All utilities 

OR Solar, wind, 

fuel cell and 

hydro 

≤25 kW 

All customer 

classes 

0.5% of peak 

demand 

Annual NEG 

granted to lowincome programs, 

credited to 

customer, or other 

use determined by 

Commission 

Legislature 1999 All utilities 

PA Renewables 

and fuel cells 

≤10 kW 

Residential None Monthly NEG 

granted to utility 

Legislature 1998 All utilities 

RI Renewables 

and fuel cells 

≤25 kW 

All customer 

classes 

1 MW for 

Narragansett 

Electric 

Company 

Annual NEG 

granted to utilities 

Public Utility 

Commission 

1998 Narragans

ett Electric 

Company 

TX Renewables 

only 

≤50 kW 

All customer 

classes 

None Monthly NEG 

purchased at 

avoided cost 

Public Utility 

Commission 

1986 All IOUs 

and RECs 

VT PV, wind, fuel 

cells 

≤15 kW 

Farm biogas 

≤150 kW 

Residential, 

commercial 

and 

agricultural 

1% of 1996 

peak 

Annual NEG 

granted to utilities 

Legislature 1998 All utilities 

113
State Allowable 

Technology 

and Size 

Allowable 

Customer 

Statewide

Limit 

Treatment of 

Net Excess 

Generation (NEG)

Authority Enacted Scope of 

Program 

VA Solar, wind 

and hydro 

Residential 

≤10 kW 

Non-residential 

≤500 kW 

All customer 

classes 

0.1% of peak 

of previous 

year 

Annual NEG 

granted to utilities 

(power purchase 

agreement is 

allowed) 

Legislature 1999 All utilities 

WA Solar, wind, 

fuel cells and 

hydro 

≤25 kW 

All customer 

classes 

0.1% of 

1996 peak 

demand 

Annual NEG 

granted to utility 

Legislature 1998 All utilities 

WI All 

technologies 

≤20 kW 

All retail 

customers 

None Monthly NEG 

purchased at retail 

rate for 

renewables, 

avoided cost for 

non-renewables 

Public 

Service 

Commission 

1993 IOUs only,

RECs are 

not rateregulated 

WY Solar, wind, 

hydro, and 

biomass ≤ 25 

kW 

All customer 

classes 

None Annual NEG 

purchased at 

avoided cost 

Legislature 2001 All IOUs, 

RECs, and 

munis 

Source: National Renewable Energy Lab based on original table by Tom Starrs of Kelso Starrs and Associates. July 2004. 

http://www.eere.energy.gov/greenpower/markets/netmetering.shtml

Notes: 

IOU — Investor-owned utility 

GandT — Generation and transmission cooperatives 

REC — Rural electric cooperative

114
3.5 – States with Environmental Disclosure Policies 

As electricity markets open to competition, retail consumers are increasingly gaining the 

ability to choose their electricity suppliers. With this choice comes the need for consumers to 

have access to information about the price, source, and environmental characteristics of their 

electricity. For green power marketers in particular, it is important that consumers understand 

the environmental implications of their energy consumption decisions. To date, 23 states and 

the District of Columbia have environmental disclosure policies in place, requiring electricity 

suppliers to provide information on fuel sources and, in some cases, emissions associated with 

electricity generation. Although most of these policies have been adopted in states with retail 

competition, a handful of states with no plans to implement restructuring have required 

environmental disclosure. 

Source: DSIRE database, June 2004. 

Figure 3.5.1. Environmental Disclosure Requirements by State 

D.C.

115
3.6 – Green Power Markets 

There are three distinct markets for green power in the United States. In regulated markets, a 

single utility may provide a green power option to its customers through “green pricing,” 

which is an optional service or tariff offered to customers. These utilities include investorowned utilities, rural electric cooperatives, and other publicly owned utilities. More than 500 

utilities in 34 states offer green pricing or are in the process of preparing programs. 

In restructured (or competitive) electricity markets, retail electricity customers can choose 

from among multiple electricity suppliers, some of which may offer green power. Electricity 

markets are now open to full competition in a number of states, while others are phasing in 

competition. 

Finally, consumers can purchase green power through “renewable energy certificates.” These 

certificates represent the environmental attributes of renewable energy generation and can be 

sold to customers in either type of market, whether or not they already have access to a green 

power product from their existing retail power provider. 

Utility market research shows that majorities of customer respondents are likely to state that 

they would pay at least $5 more per month for renewable energy. And business and other 

nonresidential customers, including colleges and universities, and government entities are 

increasingly interested in green power. 

Table 3.6.1. New Renewable Capacity Supplying Green Power Markets as of 

December 2003 (in MW) 

Source MW in Place % MW Planned % 

Wind 1544.6 93.8 306.7 78.0

Biomass 77.4 4.7 60.3 15.3

Solar 5.6 0.3 1.3 0.3

Geothermal 10.5 0.6 25.0 6.4

Small Hydro 9.3 0.6 0.0 0.0

Total 1647.3 100.0 393.4 100.0

Source: L.Bird and B. Swezey, Estimates of Renewable Energy Capacity Serving U.S. Green Power 

Markets, National Renewable Energy Laboratory, June 2004. 

http://www.eere.energy.gov/greenpower/resources/tables/new_gp_cap.shtml

 

116
Table 3.6.2: Estimated Green Power Customers and Sales by Market Segment (2003) 

Segment Customers Sales 

(Billions of kWh)* 

Utility Green Pricing 265,000 1.3

Competitive Markets 150,000 1.9

REC Markets 5,000 0.7

Retail Total 420,000 3.9

*Includes sales of new and existing renewable energy. 

Source: Bird, L. and B. Swezey, 2004. Green Power Marketing in the United States: A Status Report 

(Seventh Edition), NREL/TP-620-36823. Golden, CO: National Renewable Energy Laboratory, 

September. http://www.eere.energy.gov/greenpower/pdfs/36823.pdf

117
3.7 – States with Competitive Green Power Offerings 

Green power marketing refers to selling green power in the competitive marketplace, in which 

multiple suppliers and service offerings exist. Electricity markets are now open to full 

competition in a number of states, while others are phasing in competition, allowing some 

customers to choose their electricity supplier. As of mid-2004, competitive marketers offer 

green power to retail or wholesale customers in Maine, Maryland, Massachusetts, 

Pennsylvania, New Jersey, New York, Rhode Island, Texas, Virginia, and the District of 

Columbia. 

Source: L. Bird and B. Swezey, National Renewable Energy Laboratory. Updated July 2004. 

http://www.eere.energy.gov/greenpower/markets/marketing.shtml?page=4 

Figure 3.7.1. Green Power Marketing Map 

118
Table 3.7.1. New Renewables Capacity Supplying Competitive Markets and Renewable 

Energy Certificates, as of December 2003 (in MW) 

Source MW in Place % MW Planned % 

Wind 1,119.2 99.3 173.3 77.5

Biomass 1.7 0.1 50.3 22.5

Solar 0.7 0.1 0.0 0.0

Geothermal 5.0 0.4 0.0 0.0

Small Hydro 0.0 0.0 0.0 0.0

Total 1,126.5 100.0 223.7 100.0

Source: L.Bird and B. Swezey, Estimates of Renewable Energy Capacity Serving U.S. Green Power 

Markets, National Renewable Energy Laboratory, June 2004. 

http://www.eere.energy.gov/greenpower/resources/tables/new_gp_cap.shtml

119
Table 3.7.2. Competitive Electricity Markets Retail Green Power Product Offerings as 

of July 2004 

State/Company Product Name Residential 

Price 

Premium1

 

Fee Resource Mix2 Certification

District of Columbia 

Washington Gas 

Energy 

Services/Community 

Energy 

New Wind Energy 2.5¢/kWh — 100 kWh blocks 

of new wind 

100% Green 

Electricity 3.41¢/kWh — 

100% biomass 

— 

51% Green 

Electricity 3.05¢/kWh — 

51% biomass 

and 1% hydro — 

10% Green 

Electricity 2.74¢/kWh 

— 10% biomass — 

100% NewWind 

Energy 

4.3¢kWh 100% new wind — 

51% NewWind 

Energy 

3.42¢kWh 51% new wind — 

PEPCO Energy 

Services3

Non-residential 

product 

N/A — 50% to 100% 

eligible 

renewables 

Green-e 

Maine4

Maine Renewable 

Energy/Maine 

Interfaith Power & 

Light 

Green Supply 1.5¢/kwh — >= 50% small 

hydro, <=50% 

wood-fired 

biomass 

— 

Maine Made (nonresidential ) NA — 50% small hydro 

and 50% 

biomass 

Constellation New — 

Energy/Maine 

Power Options 

Commercial 

Renewable 

Energy (nonresidential) 

NA __ Various Green-e 

Maryland 

Washington Gas 

Energy 

Services/Community 

Energy 

New Wind Energy 2.5¢/kWh — 100 kWh blocks 

of new wind 

— 

100% Green 

Electricity 3.44¢/kWh — 

100% biomass 

— 

51% Green 

Electricity 3.08¢/kWh — 

51% biomass 

and 1% hydro 

— 

10% Green 

Electricity 2.77¢/kWh 

 10% biomass, 

2% hydro 

— 

PEPCO Energy 

Services5

100% NewWind 

Energy 

4.97¢/kWh 100% new wind — 

120
51% NewWind 

Energy 

4.09¢/kWh 51% new wind — 

Non-residential 

product 

N/A — 50% to 100% 

eligible 

renewables 

Green-e 

Massachusetts 

Constellation New 

Energy 

Commercial 

Renewable 

Energy 

(nonresidential) 

NA __ Various Green-e 

GreenerWatts 

New England 

100% 

1.9¢/kWh — 75% small 

hydro, 14% 

new* landfill 

gas, 10% 

wind, 1% new* 

solar 

Massachusetts Green-e 

Electric/Nantucket 

Electric/ 

CET & Conservation 

Services Group 

GreenerWatts 

New England 

50% 

0.95¢/kWh — 37.5% small 

hydro, 7% 

new* biomass, 

5% wind, 0.5% 

new* solar 

— 

New Wind 

Energy 100% 

2.4¢/kWh 

— 

50% small 

hydro, 50% 

new* wind 

Massachusetts Green-e 

Electric/Nantucket 

Electric/ Community 

Energy 

New Wind 

Energy 50% 

1.2¢/kWh 

— 

25% small 

hydro, 25% 

new* wind 

Green-e 

New England 

GreenStart 

100% 

2.5¢/kWh <=70% small 

hydro, >=19% 

biomass, 

10.5% wind, 

0.5% solar 

(>=25% of all 

green power is 

new*) 

Massachusetts Green-e 

Electric/Nantucket 

Electric/ Mass 

Energy Consumers 

Alliance 

New England 

GreenStart 

50% 

1.25¢/kWh — <=36.5% small 

hydro, >=10% 

biomass, 

5.25% wind, 

0.25% solar 

(>=15% of all 

green power is 

new*) 

— 

Sterling 

Premium 

1.2¢/kWh — 65% small 

hydro, 25% 

biomass, 10% 

wind 

Massachusetts — 

Electric/Nantucket 

Electric/ Sterling 

Planet 

Sterling 

Premium Plus 

2.2¢/kWh — 75% small 

hydro, 15% 

new* biomass, 

10% wind 

— 

121
New Jersey 

Constellation New 

Energy 

Commercial 

Renewable 

Energy 

(nonresidential) 

NA __ Various Green-e 

Green Mountain 

Energy Company6

Enviro Blend 0.13¢/kWh $3.95/mo. 25% biomass, 

20% small 

hydro, 5% 

wind, 50% 

large hydro 

Green-e 

New York 

1st

Rochdale/Sterling 

Planet 

Sterling Green 1.5¢/kWh — 40% new 

wind, 30% 

small hydro, 

30% biogas 

 Environmental 

Resources 

Trust 

Agway Energy 

Products/Sterling 

Planet 

Sterling Green 

Renewable 

Electricity 

1.5¢/kWh — 40% new 

wind, 30% 

small hydro, 

30% biogas 

— 

GREEN Power 

/ New Wind 

Energy 

0.5¢/kWh — 25% new 

wind, 75% 

small hydro 

ConEdison Green-e 

Solutions7 / 

Community Energy 

GREEN Power 

/ New Wind 

Energy (Nonresidential) 

NA — 100% new 

wind 

Green-e 

Constellation New 

Energy 

Commercial 

Renewable 

Energy 

(nonresidential) 

NA __ Various Green-e 

Energy Cooperative 

of New York8

Renewable 

Electricity 

0.5¢/kWh to 

0.75¢/kWh 

— 25% new 

wind, 75% 

existing landfill 

gas 

— 

Green Choice / 

New Wind 

Energy 

2.0¢/kWh 100% new 

wind 

Long Island Power — 

Authority / 

Community Energy 

Green Choice / 

New Wind 

Energy and 

Water 

1.0¢/kWh 60% new 

wind, 40% 

small hydro 

— 

Long Island Power 

Authority / 

EnviroGen 

Green Choice / 

Green Power 

Program 

1.0¢/kWh 75% landfill 

gas, 25% 

small hydro 

— 

Green Choice / 

Sterling Green 

1.5¢/kWh 40% wind, 

30% small 

hydro, 30% 

bioenergy 

Long Island Power — 

Authority / Sterling 

Planet 

Green Choice / 

New York 

Clean 

1.0¢/kWh 55% small 

hydro, 35% 

bioenergy, 

10% wind 

— 

122
60% New Wind 

Energy and 

40% Small 

Hydro 

1.0¢/kWh — 60% new 

wind, 40% 

hydro 

Green-e 

100% 

NewWind 

Energy 

2.0¢/kWh — 100% new 

wind 

Green-e 

Niagara 

Mohawk/Community 

Energy 

Blocks of 

NewWind 

Energy 

2.0¢/kWh — 100 kWh 

blocks of new 

wind 

Green-e 

Niagara Mohawk / 

EnviroGen 

Think Green! 1.0¢/kWh — 75% landfill 

gas, 25% 

hydro 

— 

Niagara 

Mohawk/Green 

Mountain Energy 

Green 

Mountain 

Energy 

Electricity 

1.3¢/kWh — 50% wind, 

50% small 

hydro 

Green-e 

Niagara 

Mohawk/Sterling 

Planet 

Sterling Green 1.5¢/kWh — 40% wind, 

30% small 

hydro, 30% 

bioenergy 

— 

NYSEG / 

Community Energy 

Catch The 

Wind / New 

Wind Energy 

2.0-

2.5¢/kWh 

— 100-kWh 

blocks of new 

wind 

Green-e 

Rochester Gas & 

Electric/Community 

Energy 

Catch the Wind 2.0-

2.5¢/kWh 

— 100-kWh 

blocks of new 

wind 

Green-e 

Select Energy Non-residential 

product 

N/A — Wind — 

Pennsylvania9

ElectricAmerica 50% Hydro 0.39¢/kWh — 50% large 

hydro 

— 

Eco Choice 

100 

1.08¢/kWh $5/year 90% landfill 

gas, 10% 

wind, 0.1% 

solar 

Energy Cooperative Green-e 

of Pennsylvania 

New Wind 

Energy 

2.5¢/kWh — Wind — 

Green 

Mountain 

Energy 

Electricity 

1.37¢/kWh $3.95/mo. 10% wind, 

90% 

hydropower 

Green Mountain — 

Energy Company 

Nature’s 

Choice 

1.39¢/kWh $3.95/mo. 60% biomass, 

30% small 

hydro, 10% 

wind, < 1% 

solar 

Green-e 

PECO 

Energy/Community 

Energy 

PECO Wind 2.54¢/kWh — 100-kWh 

blocks of new 

wind 

— 

100% 

Renewable 

3.39¢/kWh — 100% 

renewable 

PEPCO Energy — 

Services 

51% Green 

Electricity 

3.0¢/kWh 

— 

51% biomass 

and 1% hydro — 

123
10% Green 

Electricity 

2.67¢/kWh — 10% biomass — 

100% 

NewWind 

Energy 

4.5¢/kWh 100% new 

wind 

— 

51% NewWind 

Energy 

3.57¢/kWh 51% new wind — 

Rhode Island 

Constellation New 

Energy 

Commercial 

Renewable 

Energy 

(nonresidential) 

NA __ Various Green-e 

NewWind 

Energy 100% 

2.0¢/kWh 

— 

50% small 

hydro, 50% 

new* wind 

Narragansett Green-e 

Electric / Community 

Energy, Inc. 

NewWind 

Energy 50% 

1.0¢/kWh — 25% small 

hydro, 25% 

new* wind 

Green-e 

Narragansett 

Electric / 

Conservation 

Services Group 

GreenerWatts 

New England 

100% 

1.7¢/kWh — 75% small 

hydro, 14% 

new* landfill 

gas, 10% 

wind, 1% new* 

solar 

Green-e 

New England 

GreenStart RI 

100% 

1.5¢/kWh — 69% small 

hydro, 30% 

new* wind, 1% 

new* solar 

Narragansett Green-e 

Electric / People’s 

Power & Light 

New England 

GreenStart RI 

50% 

0.75¢/kWh — 34.5% small 

hydro, 15% 

new* wind, 

0.5% new* 

solar 

Green-e 

Narragansett 

Electric / Sterling 

Planet 

Sterling 

Supreme 

100% 

1.98¢/kWh — 40% small 

hydro, 25% 

biomass, 25% 

new* solar, 

10% wind, 

— 

Texas10

100% Wind 

Power 

0.66¢/kWh $4.95/mo. 100% wind — 

Reliable Rate 

Plan 

0.46¢/kWh $4.95/mo. Wind and 

hydro 

— 

Green Mountain 

Energy Company 

Month-toMonth Plan 0.26¢/kWh $4.95/mo. Wind and 

hydro 

— 

Reliant Energy Renewable 

Plan 

0.0¢/kWh $5.34/mo. 100% 

renewable 

energy 

— 

Strategic Energy Non-residential 

product 

N/A — Wind — 

TXU Energy Non-residential 

product 

N/A — Wind — 

124
Virginia 

Washington Gas 

Energy 

Services/Community 

Energy 

New Wind 

Energy 

2.5¢/kWh — 100 kWh 

blocks of new 

wind 

— 

100% Green 

Electricity 4.367¢/kWh — 

100% biomass — 

51% Green 

Electricity 3.997¢/kWh — 

51% biomass 

and less than 

1% hydro 

— 

10% Green 

Electricity 3.687¢/kWh 

— 10% biomass — 

100% 

NewWind 

Energy 

5.027¢/kWh — 100% new 

wind 

— 

PEPCO Energy 

Services11

51% NewWind 

Energy 

4.147¢/kWh — 51% new wind — 

Source: National Renewable Energy Laboratory. 

Notes: 

N/A= Not applicable. 

1

 Prices may vary by service territory. Prices may also differ for commercial/industrial customers. 2 New is defined as operating or repowered after January 1, 1999 based on the Green-e TRC certification 

standards. New power sources denoted with an asterisk (*) are new as of January 1, 1998. 3

 Offered in PEPCO service territory. Product prices are based on annual average costs for customers in 

PEPCO’s service territory (5.04¢/kWh). http://www.dcpsc.org/customerchoice/whatis/electric/electric.shtm 4

 Price premium is for Central Maine Power service territory. 

5

 Product offered in Baltimore Gas and Electric and PEPCO service territories. Price is for PEPCO service 

territory based on price to compare of 5.01¢/kWh. http://www.oag.state.md.us/energy/ 6

 Green Mountain Energy offers products in Conectiv, GPU, and PSE&G service territories. Product prices are 

for Conectiv service territory (price to compare of 6.75¢/kWh). 7

 Price premium is based on a comparison to ConEdison Solutions’ standard electricity product. 

8

 Price premium is for Niagara Mohawk service territory. Premium varies depending on energy taxes. 

9

 Product prices are for PECO service territory (price to compare of 6.17¢/kWh). 

http://www.oca.state.pa.us/elecomp/pricecharts.html 10 Product prices are based on price to beat of 10.4¢/kWh for TXU service territory (ONCOR). 

http://www.powertochoose.org/ 

11 Products are only available in Dominion Virginia Power service territory. Price is based on price to compare of 

3.983¢/kWh 

References: 

Green power marketer and utility Web sites. 

District of Columbia Public Service Commission 

http://www.dcpsc.org/customerchoice/whatis/electric/electric.shtm

Maryland Attorney General Electricity Supplier Rate and Service Information http://www.oag.state.md.us/energy/

Pennsylvania Office of Consumer Advocate Residential Price Comparison Charts 

http://www.oca.state.pa.us/elecomp/pricecharts.html 

Virginia’s State Corporation Commission http://www.yesvachoice.com/howtochoose/howtoccompare.asp 

Texas Public Utility Commission http://www.powertochoose.org/

125
3.8 – States with Utility Green Pricing Programs 

Green pricing is an optional utility service that allows customers an opportunity to support a 

greater level of utility company investment in renewable energy technologies. Participating 

customers pay a premium on their electric bill to cover the extra cost of the renewable energy. 

Many utilities are offering green pricing to build customer loyalty, as well as expand business 

lines and expertise prior to electric market competition. To date, more than 500 investorowned, municipal, and cooperative utilities in 34 states have either implemented or 

announced plans to offer a green pricing option. 

Source: L. Bird and B. Swezey, National Renewable Energy Laboratory. Updated April 2004. 

http://www.eere.energy.gov/greenpower/markets/pricing.shtml?page=4 

Figure 3.8.1. Number of Utilities Offering Green Pricing Programs by State 

126
Table 3.8.1. New Renewables Capacity Supported through Utility Green Pricing 

Programs, as of December 2003 (in MW) 

Source MW in Place % MW Planned % 

Wind 425.4 81.7 133.4 78.6

Biomass 75.7 14.5 10.0 5.9

Solar 4.9 0.9 1.3 0.8

Geothermal 5.5 1.1 25.0 14.7

Small Hydro 9.3 1.8 0.0 0.0

Total 520.8 100.0 169.7 100.0

Source: L.Bird and B. Swezey, Estimates of Renewable Energy Capacity 

Serving U.S. Green Power Markets, National Renewable Energy Laboratory, June 2004. 

http://www.eere.energy.gov/greenpower/resources/tables/new_gp_cap.shtml

Table 3.8.2. Utility Green Pricing Programs, April 2004 

State Utility Name Program 

Name 

Resource 

Type 

Start 

Date 

Premium 

AL Alabama Power Renewable Energy 

Rate 

biomass cofiring 2003/

2000

6.0¢/ kWh

AL TVA: City of Athens Electric Department, 

Cullman Electric Coop, Cullman Power 

Board, Decatur Utilities, Florence Utilities, 

Hartselle Utilities, Huntsville Utilities, Joe 

Wheeler EMC, Muscle Shoals Electric 

Board, Scottsboro Electric Power Board, 

Sheffield Utilities, Tuscumbia Electric 

Department 

Green Power 

Switch 

wind, landfill 

gas, solar 

2000 2.67¢/ kWh

AZ Arizona Public Service Solar Partners 

Program 

central PV 1997$2.64/ 15kWh

AZ Salt River Project EarthWise Energy central PV, 

landfill gas, 

small hydro 

1998/

2001

3.0¢/kWh

AZ Tucson Electric GreenWatts landfill gas, 

PV, wind 

2000 7.5-10¢/ kWh

CA City of Alameda Clean Future Fund various, 

electric 

vehicles 

1999 1.0¢/kWh

CA City of Palo Alto Utilities/3 Phases Energy 

Services 

Palo Alto Green wind, solar 2003/

2000

1.5¢/kWh

CA Los Angeles Dept. of Water and Power Green Power for a 

Green LA 

wind, landfill 

gas 

1999 3.0¢/kWh

CA Pasadena Water & Power Green Power wind 2003 2.5¢/kWh

CA Roseville Electric RE Green Energy 

Program 

geothermal, 

hydro, PV 

2000 1.0¢/kWh

127
CA Sacramento Municipal Utility District Greenergy wind, landfill 

gas, hydro 

1997 1.0¢/kWh

CA Sacramento Municipal Utility District PV Pioneers I PV 1993 $4/month

CO Colorado Springs Utilities Green Power wind 1997 3.0¢/kWh

CO Holy Cross Energy Local Renewable 

Energy Pool 

small hydro, 

PV 

2002 3.3¢/kWh

CO Holy Cross Energy Wind Power 

Pioneers 

wind 1998 2.5¢/kWh

CO Platte River Power Authority (Estes Park, 

Fort Collins Utilities, Longmont Power & 

Communications, Loveland Water & Light)

Wind Power 

Program 

wind 1996 2.5¢/kWh

CO Tri-State Generation & Transmission (18 of 

44 coops): Carbon Power, Chimney Rock, 

Gunnison County Electric, Kit Carson, La 

Plata Electric, Mountain Parks Electric, 

Mountain View Electric, New Mexico, 

Northwest Rural, Poudre Valley Rural 

Electric Association, Public Power District, 

Sangre, San Isabel Electric, San Luis 

Valley Rural Electric Coop, San Miguel 

Power, Springer Electric, United Power, 

White River 

Renewable 

Resource Power 

Service 

wind, landfill 

gas 

1999 2.5¢/kWh

CO Xcel Energy WindSource wind 1997 2.5¢/kWh

CO Xcel Energy Renewable Energy 

Trust 

PV 1993 Contribution

CO Yampa Valley Electric Association Green Power wind 1999 3.0¢/kWh

FL City of Tallahassee/Sterling Planet Green for You biomass, 

solar 

2002 1.6¢/kWh

FL City of Tallahassee/Sterling Planet Green for You solar only 2002 11.6¢/kWh

FL Florida Power & Light/Green Mountain 

Energy 

Sunshine Energy biomass, 

wind, solar 

2004 0.975¢/kWh

FL Gainesville Regional Utilities GRUgreen Energy landfill gas, 

wind, solar 

2003 2.0¢/kWh

FL Southern Company: Gulf Power Company EarthCents Solar PV in 

schools; 

central PV 

1996/

1999

Contribution; 

$6.00/ 100 

watts

FL Tampa Electric Company (TECO) Tampa Electric's 

Renewable Energy 

Program 

PV, landfill 

gas 

2000 10.0¢/kWh

FL Utilities Commission City of New Smyrna 

Beach 

Green Fund local PV 

projects 

1999 Contribution

GA Georgia Electric Membership Corporation 

(16 of 42 coops offer program): 

Carroll EMC, Coastal Electric, Cobb EMC, 

Coweta-Fayette EMC, Flint Energies, 

GreyStone Power, Habersham EMC, Irwin 

EMC, Jackson EMC, Jefferson Energy, 

Lamar EMC, Ocmulgee EMC, Sawnee 

EMC, Snapping Shoals EMC, Tri-County 

EMC, Walton EMC of Monroe 

Green Power EMC landfill gas 2001 TBD

GA Georgia Power Green Energy landfill gas, 

wind, solar 

TBD 5.5¢/kWh

GA Savannah Electric Green Energy landfill gas, 

wind, solar 

TBD 6.0¢/kWh

128
GA TVA: Blue Ridge Mountain Electric 

Membership Corporation, North Georgia 

Electric Membership Corporation 

Green Power 

Switch 

wind, landfill 

gas, solar 

2000 2.67¢/ kWh

HI Hawaiian Electric Sun Power for 

Schools 

PV in 

schools 

1996 Contribution

IA Alliant Energy Second Nature wind, landfill 

gas 

2001 2.0¢/kWh

IA Basin Electric Power Cooperative: Lyon 

Rural, Harrison County, Nishnabotna 

Valley Cooperative, Northwest Rural 

Electric Cooperative, Western Iowa 

Prairie Winds wind 2000 1.0¢/kWh

IA Cedar Falls Utilities Wind Energy 

Electric Project 

wind 1999 Contribution

IA Corn Belt Power Cooperatives: (11 co-ops 

and 1 municipal cooperative) Boone Valley 

Electric Cooperative, Butler County REC, 

Calhoun County REC, Franklin REC, 

Glidden REC, Grundy County REC, 

Humboldt County REC, Iowa Lakes 

Electric Cooperative, Midland Power 

Cooperative, Prairie Energy Cooperative, 

Sac County REC, North Iowa Municipal 

Electric Cooperative Association 

Varies by Utility wind 2004 Contribution

IA Dairyland Power Cooperative: AllamakeeClayton/Postville, Hawkeye TriCounty/Cresco, Heartland 

Power/Thompson & St. Ansgar 

Evergreen 

Renewable Energy 

Program 

wind 1997 3.0¢/kWh

IA Farmers Electric Cooperative Green Power 

Project 

biodiesel, 

wind 

2004 Contribution

IA Iowa Association of Municipal Utilities (80 

of 137 participating) Afton, Algona, Alta 

Vista, Aplington, Auburn, Bancroft, 

Bellevue, Bloomfield, Breda, Brooklyn, 

Buffalo, Burt, Callender, Carlisle, Cascade, 

Coggon, Coon Rapids, Corning, Corwith, 

Danville, Dayton, Durant, Dysart, Earlville, 

Eldridge, Ellsworth, Estherville, Fairbank, 

Farnhamville, Fontanelle, Forest City, 

Gowrie, Grafton, Grand Junction, 

Greenfield, Grundy Center, Guttenberg, 

Hopkinton, Hudson, Independence, 

Keosauqua, La Porte City, Lake Mills, 

Lake View, Laurens, Lenox, Livermore, 

Maquoketa, Marathon, McGregor, Milford, 

Montezuma, Mount Pleasant, Neola, New 

Hampton, Ogden, Orient, Osage, Panora, 

Pella, Pocahontas, Preston, Readlyn, 

Rockford, Sabula, Sergeant Bluff, Sibley, 

Spencer, Stanhope, State Center, 

Stratford, Strawberry Point, Stuart, Tipton, 

Villisca, Vinton, Webster City, West Bend, 

West Liberty, West Point, Westfield, 

Whittemore, Wilton, Winterset 

Green City Energy wind, 

biomass, 

solar 

2003 Varies by 

utility

IA MidAmerican Energy Renewable 

Advantage 

wind 2004 Contribution

129
IA Missouri River Energy Services (MRES): 

Alton, Atlantic, Denison, Fontanelle, 

Hartley, Hawarden, Kimballton, Lake Park, 

Manilla, Orange City, Paullina, Primghar, 

Remsen, Rock Rapids, Sanborn, Shelby, 

Sioux Center, Woodbine 

RiverWinds wind 2003 2.0 -

2.5¢/kWh

IA Muscatine Power and Water Solar Muscatine solar 2004 Contribution

IA Waverly Light & Power Iowa Energy Tags wind 2001 2.0¢/kWh

ID Avista Utilities Buck-A-Block wind 2002 1.8¢/kWh

ID Idaho Power Green Power 

Program 

various 2001 Contribution

ID PacifiCorp: Utah Power Blue Sky wind 2003 1.95¢/kWh

ID Vigilante Electric Cooperative Alternative 

Renewable Energy 

Program 

wind, solar, 

hydro 

2003 1.1¢/kWh

IL City of St. Charles/ComEd and Community 

Energy, Inc. 

TBD wind, landfill 

gas 

2003 Contribution

IL Dairyland Power Cooperative: Jo-Carroll 

Energy/Elizabeth 

Evergreen 

Renewable Energy 

Program 

wind 1997 3.0¢/kWh

IN Hoosier Energy (5 of 17 coops): 

Southeastern Indiana REMC, South 

Central Indiana REMC, Utilities District of 

Western Indiana REMC, Decatur County 

REMC, Daviess-Martin County REMC 

EnviroWatts landfill gas 2001 2.0¢/kWh -

4.0¢/kWh

IN Indianapolis Power & Light Elect PlanSM 

Green Power 

Program 

geothermal 1998 0.9¢/kWh

IN PSI Energy/Cinergy Green Power Rider wind, solar, 

landfill gas, 

digester gas 

2001 Contribution

IN Wabash Valley Power Association (7 of 27 

coops offer program): Boone REMC, 

Hendricks Power Cooperative, Kankakee 

Valley REMC, Miami-Cass REMC, 

Tipmont REMC, White County REMC, 

Northeastern REMC 

EnviroWatts landfill gas 2000 0.9-1.0¢/kWh

KY East Kentucky Power Cooperative: 

Bluegrass, Clark, Inter County Energy 

Cooperative, Owen, Nolin, Salt River, 

Grayson, South Kentucky, Shelby, 

Cumberland, Licking, Jackson, Mason, 

Fleming 

EnviroWatts landfill gas 2002 2.75¢/kWh

KY TVA: Bowling Green Municipal Utilities, 

Franklin Electric Plant Board 

Green Power 

Switch 

landfill gas, 

solar, wind 

2000 2.67¢/kWh

MA Concord Municipal Light Plant (CMLP) Green Power hydro 2004 3.0¢/kWh

MI Consumers Energy Green Power Pilot 

Program 

wind 2001 3.2¢/kWh

MI DTE Energy Solar Currents central PV 1996 $6.94/100 

watts

MI Lansing Board of Water and Light GreenWise Electric 

Power 

landfill gas, 

small hydro 

2001 3.0¢/kWh

MI Traverse City Light and Power Green Rate wind 1996 1.58¢/kWh

MI We Energies Energy for 

Tomorrow 

wind, landfill 

gas, hydro 

2000 2.04¢/kWh

130
MN Alliant Energy Second Nature wind, landfill 

gas 

2002 2.0¢/kWh

MN Basin Electric Power Cooperative: 

Minnesota Valley Electric Coop, Sioux 

Valley Southwestern 

Prairie Winds wind 2000 1.0¢/kWh

MN Dairyland Power Cooperative: FreebornMower Cooperative/Albert Lea, 

People’s/Rochester, Tri-County/Rushford 

Evergreen 

Renewable Energy 

Program 

wind 1997 3.0¢/kWh

MN Great River Energy (28) : Agralite Electric 

Cooperative, Arrowhead Electric 

Cooperative, BENCO Electric, Brown 

County Rural Electric, Connexus Energy, 

Co-op Light & Power, Crow Wing Power, 

Dakota Electric Association, East Central 

Electric Association, Federated Rural 

Electric, Goodhue County, Itasca Mantrap 

Cooperative, Kandiyohi Power 

Cooperative, Lake Country Power, Lake 

Region Electric Cooperative, McLeod 

Cooperative Power, Meeker Cooperative 

Light & Power, Mille Lacs Electric 

Cooperative, Minnesota Valley Electric 

Cooperative, Nobles Cooperative Electric, 

North Itasca, Redwood Electric 

Cooperative, Runestone Electric, South 

Central Electric Association, Stearns 

Electric, Steele-Waseca, Todd-Wadena, 

Wright-Hennepin Electric 

Wellspring wind 1997 1.45-

2.0¢/kWh

MN Minnesota Power WindSense wind 2002 2.5¢/kWh

MN Minnkota Power Cooperative: Beltrami, 

Clearwater Polk, North Star, PKM, Red 

Lake, Red River, Roseau, Wild Rice, Thief 

River Falls 

Infinity Wind 

Energy 

wind 1999 1.5¢/kWh

MN Missouri River Energy Services (39 of 55): 

Adrian, Alexandria, Barnesville, Benson, 

Breckenridge, Detroit Lakes, Elbow Lake, 

Henning, Jackson, Lakefield, Lake Park, 

Luverne, Madison, Moorhead, Ortonville, 

St. James, Sauk Centre, Staples, Wadena, 

Westbrook, Worthington 

RiverWinds wind 2002 2.0-2.5¢/kWh

MN Moorhead Public Service Capture the Wind wind 1998 1.5¢/kWh

MN Otter Tail Power TailWinds wind 2002 2.6¢/kWh

MN Southern Minnesota Municipal Power 

Agency (all 18 munis offer program): 

Fairmont Public Utilities, Wells Public 

Utilities, Austin Utilities, Preston Public 

Utilities, Spring Valley Utilities, Blooming 

Prairie Public Utilities, Rochester Public 

Utilities, Owatonna Public Utilities, Waseca 

Utilities, St. Peter Municipal Utilities, Lake 

City Utilities, New Prague Utilities 

Commission, Redwood Falls Public 

Utilities, Litchfield Public Utilities, Princeton 

Public Utilities, North Branch Water and 

Light, Mora Municipal Utilities, Grand 

Marais Public Utilities 

Wind Power wind 2000 1.0¢/kWh

MN Xcel Energy WindSource wind 2003 2.0¢/kWh

131
MO Boone Electric Cooperative Renewable Choice wind 2003 2.0¢/kWh

MO City Utilities of Springfield WindCurrent wind 2000 5.0¢/kWh

MS TVA: City of Oxford, North East Mississippi 

Electric Power Association, Starkville 

Electric System 

Green Power 

Switch 

wind, landfill 

gas, solar 

2000 2.67¢/kWh

MT Basin Electric Power Cooperative: Lower 

Yellowstone 

Prairie Winds wind 2000 1.0¢/kWh

MT Northwestern Energy E+ Green wind, solar 2003 2.0¢/kWh

MT Vigilante Electric Cooperative Alternative 

Renewable Energy 

Program 

wind, solar, 

hydro 

2003 1.1¢/kWh

NC Dominion North Carolina Power, Duke 

Power, Progress Energy/CP&L 

ElectriCities (7 of 57) City of High Point, 

City of Laurinburg, City of Newton, City of 

Shelby, City of Statesville,Town of Apex, 

Town of Granite Falls 

NC Electric Cooperatives (14 of 27 

cooperatives offer the program): Blue 

Ridge Electric Membership Corp., 

Brunswick Electric Membership Corp., 

Carteret Craven Electric Coop., 

Edgecombe-Martin County Electric 

Membership Corp., EnergyUnited, Four 

County Electric Membership Corp., 

Haywood Electric Membership Corp., 

Jones-Onslow Electric Membership Corp., 

Pee Dee Electric Membership Corp., 

Piedmont Electric Membership Corp., 

Randolph Electric Membership Corp., 

Roanoke Electric Membership Corp., TriCounty Electric Membership Corp., Wake 

Electric Membership Corp. 

NC GreenPower biomass, 

wind, solar 

2003 4.0¢/kWh

NC TVA: Mountain Electric Cooperative Green Power 

Switch 

landfill gas, 

solar, wind 

2000 2.67¢/kWh

ND Basin Electric Power Cooperative (49 

coops offer program in 5 states): Oliver 

Mercer Electric Coop, Mor-gran-sou 

Electric Coop, KEM Electric Coop, North 

Central Electric Coop, Verendrye, Capital 

, Northern Plains, Dakota Valley, Burke 

Divide, Montrail Williams, McKenzie 

Electric Coop, West Plains, Slope Electric 

Coop 

PrairieWinds wind 2000 1.0¢/kWh

ND Minnkota Power Cooperative: Cass 

County Electric, Cavalier Rural Electric, 

Nodak Electric, Northern Municipal Power 

Agency (12 municipals) 

Infinity Wind 

Energy 

wind 1999 1.5¢/kWh

ND Missouri River Energy Services: City of 

Lakota 

RiverWinds wind 2002 2.0-2.5¢/kWh

NE Lincoln Electric System Renewable Energy 

Program 

wind 1998 4.3¢/kWh

NE Nebraska Public Power District Prairie Power 

Program 

TBD 1999 Contribution

NE Omaha Public Power District Green Power 

Program 

landfill gas, 

wind 

2002 3.0¢/kWh

132
NE Tri-State: Chimney Rock Public Power 

District, Northwest Rural Public Power 

District 

Renewable 

Resource Power 

Service 

wind, landfill 

gas 

2001 2.5¢/kWh

NM El Paso Electric Renewable Energy 

Tariff 

wind 2003 3.19¢/kWh

NM Public Service of New Mexico PNM Sky Blue wind 2003 1.8¢/kWh

NM Tri-State: Kit Carson Electric Cooperative Renewable 

Resource Power 

Service 

wind, landfill 

gas 

2001 2.5¢/kWh

NM Xcel Energy WindSource wind 1999 3.0¢/kWh

OH AMP Ohio/Green Mountain Energy: 

Cuyahoga Falls 

Nature's Energy small hydro, 

wind, landfill 

gas 

2003 1.3¢/kWh

OH City of Bowling Green Bowling Green 

Power 

small hydro, 

wind, landfill 

gas 

1999 1.35¢/kWh

OK Edmond Electric Pure & Simple wind 2004 1.8¢/kWh

OK OG&E Electric Services Wind Power wind 2003 0.63¢/kWh

OR City of Ashland/Bonneville Environmental 

Foundation 

Renewable 

Pioneers 

solar 2003 2.0¢/kWh

OR Emerald People's Utility District/Green 

Mountain Energy 

Choose 

Renewable 

Electricity 

wind, 

geothermal 

2003 0.78-

1.2¢/kWh

OR Eugene Water & Electric Board EWEB Wind Powerwind 1999 1.3¢/kWh

OR Midstate Electric Cooperative Environmentally 

Preferred Power 

wind, small 

hydro 

1999 2.5¢/kWh

OR Oregon Trail Electric Cooperative Green Power wind 2002 1.5¢/kWh

OR Pacific Northwest Generating Cooperative 

(5 of 16 coops offer program): Central 

Electric Cooperative, Clearwater Power, 

Consumers Power, Douglas Electric 

Cooperative, Umatilla Electric Cooperative

Green Power landfill gas 1998 1.8-2.0¢/kWh

OR PacifiCorp: Pacific Power Blue Sky Block wind 2000 1.95¢/kWh

OR PacifiCorp: Pacific Power/3 Phases 

Energy Services 

Blue Sky Usage existing 

geothermal, 

wind 

2002 0.78¢/kWh

OR PacifiCorp: Pacific Power/3 Phases 

Energy Services 

Blue Sky Habitat existing 

geothermal, 

wind 

2002 0.78¢/kWh + 

$2.50 

donation

OR Portland General Electric/Green Mountain 

Energy 

Green Mountain 

Renewable Energy 

Usage 

existing 

geothermal, 

wind 

2002 0.8¢/kWh

OR Portland General Electric/Green Mountain 

Energy 

Healthy Habitat existing 

geothermal, 

wind 

2002 0.99¢/kWh

OR Portland General Electric Company Clean Wind for 

Medium to Large 

Commercial and 

Industrial Accounts

wind 2003 1.5-1.7¢/kWh

OR Portland General Electric Company Clean Wind Power wind 2000 3.5¢/kWh

133
SC Santee Cooper, Aiken Electric 

Cooperative, Berkeley Electric 

Cooperative, Horry Electric Cooperative, 

Mid-Carolina Electric Cooperative, 

Palmetto Electric Cooperative, Santee 

Electric Cooperative, Tri-County Electric 

Cooperative 

Green Power 

Program 

landfill gas 2001 3.0¢/kWh

SD Basin Electric Power Cooperative: 

Bon Homme-Yankton Electric Assn., 

Central Electric Cooperative Association, 

Charles Mix Electric Association, City of 

Elk Point, Clay-Union Electric Corporation, 

Codington-Clark Electric Cooperative, 

Dakota Energy Cooperative, Douglas 

Electric Cooperative, FEM Electric 

Association, H-D Electric Cooperative, 

Kingsbury Electric Cooperative, LyonLincoln Electric Cooperative, McCook 

Electric Cooperative, Northern Electric 

Cooperative, Oahe Electric Cooperative, 

Renville-Sibley Coop, Sioux Valley 

Southwestern Electric Coop, Southeastern 

Electric Coop, Union County Electric 

Cooperative, Whetstone Valley Electric 

Cooperative, Black Hills Electric Coop, 

LaCreek Electric Coop, West River Power 

Association, Butte Electric Coop, Cherry 

Todd Electric Coop, Moreau Grand, Grand 

Electric Cooperative, Rosebud 

Prairie Winds wind 2000 1.0¢/kWh

SD Missouri River Energy Services: City of 

Vermillion 

RiverWinds wind 2002 2.0-2.5¢/kWh

134
TN Alcoa Electric Department, Appalachian 

Electric Cooperative, Athens Utility Board, 

Bristol Tennessee Electric System, Caney 

Fork Electric Cooperative, City of Maryville 

Electric Department, Clarksville 

Department of Electricity, Cleveland 

Utilities, Clinton Utilities Board, Cookeville 

Electric Department, Cumberland Electric 

Membership Corporation, Dickson Electric 

Department, Duck River Electric 

Membership Corporation, Elizabethton 

Electric System, EPB (Chattanooga), 

Erwin Utilities, Fayetteville Public Utilities, 

Gibson Electric Membership Corporation, 

Greeneville Light and Power System, 

Harriman Utility Board, Johnson City 

Power Board, Jackson Energy Authority, 

Knoxville Utilities Board, Lafollette Utilities 

Board, Lawrenceburg Power System, 

Lenoir City Utilities Board, Loudon Utilities, 

McMinnville Electric System, Meriwhether 

Lewis Electric Cooperative, Middle 

Tennessee Electric Membership 

Corporation, Morristown Power System, 

Mountain Electric Cooperative, 

Murfreesboro Electric Department, 

Nashville Electric Service, Newport 

Utilities, Oak Ridge Electric Department, 

Paris Board of Public Utilities, Plateau 

Electric Cooperative, Powell Valley Electric 

Cooperative, Pulaski Electric System, 

Sequachee Valley Electric Cooperative, 

Sevier County Electric System, Springfield 

Department of Electricity, Sweetwater 

Utilities Board, Tullahoma Utilities Board, 

Upper Cumberland Electric Membership 

Corporation, Volunteer Energy 

Cooperative 

Green Power 

Switch 

biogas, solar, 

wind 

2000 2.67¢/kWh

TX Austin Energy GreenChoice wind, hydro, 

landfill gas 

2000/

1997

0.5¢/kWh

TX City Public Service of San Antonio Windtricity wind 2000 3.0¢/kWh

TX El Paso Electric Renewable Energy 

Tariff 

wind 2001 1.92¢/kWh

UT PacifiCorp: Utah Power Blue Sky wind 2000 1.95¢/kWh

VT Central Vermont Public Service CVPS Cow Power biogas TBD 4¢/kWh

VT Green Mountain Power CoolHome, 

CoolBusiness 

wind, 

biomass 

2002 Contribution

WA Avista Utilities Buck-A-Block wind 2002 1.82¢/kWh

WA Benton County Public Utility District Green Power 

Program 

landfill gas, 

wind 

1999 Contribution

WA Chelan County PUD Sustainable 

Natural Alternative 

Power (SNAP) 

PV, wind, 

micro hydro 

2001 Contribution

WA Clallam County PUD Green Power Rate landfill gas 2001 0.7¢/kWh

WA Clark Public Utilities Green Lights PV, wind 2002 1.5¢/kWh

135
WA Cowlitz PUD Renewable 

Resource Energy 

wind, PV 2002 2.0¢/kWh

WA Grant County PUD Alternative Energy 

Resources 

Program 

wind 2002 2.0¢/kWh

WA Grays Harbor PUD Green Power 

Program 

wind 2002 3.0¢/kWh

WA Lewis County PUD Green Power 

Energy Rate 

wind 2003 2.0¢/kWh

WA Mason County PUD No. 3 Mason EverGreen 

Power 

wind 2003 2.0¢/kWh

WA Orcas Power & Light Go Green small hydro, 

wind, PV 

1997 3.5¢/kWh

WA Pacific County PUD Green Power wind, hydro 2002 1.05¢/kWh

WA PacifiCorp: Pacific Power Blue Sky wind 2000 1.95¢/kWh

WA Peninsula Light Green by Choice wind, hydro 2002 2.8¢/kWh

WA Puget Sound Energy Green Power wind, solar 2002 2.0¢/kWh

WA Seattle City Light Seattle Green 

Power Program 

solar, wind, 

biogas 

2002 Contribution

WA Snohomish County PUD Planet Power wind 2002 2.0¢/kWh

WA Tacoma Power EverGreen Options small hydro, 

wind 

2000 Contribution

WI Alliant Energy Second Nature wind, landfill 

gas 

2000 2.0¢/kWh

WI Dairyland Power Cooperative: Barron 

Electric, Bayfield/Iron River, 

Chippewa/Cornell Valley, 

Clark/Greenwood, Dunn/Menomonie, Eau 

Claire/Fall Creek, Jackson/Black River 

Falls, Jump River/Ladysmith, Oakdale, 

Pierce-Pepin/Ellsworth, PolkBurnett/Centuria, Price/Phillips, Richland, 

Riverland/Arcadia, St. Croix/Baldwin, 

Scenic Rivers/Lancaster, Taylor/Medford, 

Vernon/Westby 

Evergreen 

Renewable Energy 

Program 

wind 1997 3.0¢/kWh

WI Great River Energy: Head of the Lakes Wellspring wind 1997 1.28-

2.0¢/kWh

WI Madison Gas & Electric Wind Energy 

Program 

wind 1999 3.33¢/kWh

WI We Energies Energy for 

Tomorrow 

landfill gas, 

hydro, wind 

1996 2.04¢/kWh

WI Wisconsin Public Power Inc. (34 of 37 

munis offer program): 

Algoma, Cedarburg, Florence, Kaukauna, 

Muscoda, Stoughton, Reedsburg, 

Oconomowoc, Waterloo, Whitehall, 

Columbus, Hartford, Lake Mills, New 

Holstein, Richland Center, Boscobel, Cuba 

City, Hustisford, Sturgeon Bay, Waunakee, 

Lodi, New London, Plymouth, River Falls, 

Sun Prairie, Waupun, Eagle River, 

Jefferson, Menasha, New Richmond, 

Prairie du Sac, Slinger, Two Rivers, 

Westby 

Renewable Energy 

Program 

small hydro, 

wind, biogas 

2001 2.0¢/kWh

WI Wisconsin Public Service NatureWise Wind, landfill 

gas, biogas 

2002 2.65¢/kWh

136
WI Wisconsin Public Service SolarWise for 

Schools 

PV 

installations 

on schools 

1997 Contribution

WY Lower Valley Energy Green Power wind 2003 1.67¢/kWh

WY PacifiCorp: Pacific Power Blue Sky wind 2000 1.95¢/kWh

WY Tri-State: Carbon Power & Light Renewable 

Resource Power 

Service 

wind, landfill 

gas 

2001 2.5¢/kWh

Source: L. Bird and B. Swezey, National Renewable Energy Laboratory 

http://www.eere.energy.gov/greenpower/markets/pricing.shtml?page=1

 Source: L. Bird and B. Swezey, 2004. 

Figure 3.8.2. Growth Trend in Utility Green Pricing Programs, 1993-2003 

Table 3.8.3. Estimated Cumulative Number of Customers Participating in Utility Green 

Pricing Programs 

Customer Segment 1999 2000 2001 2002 2003

Residential n/a* 131,000 166,300 224,500 258,700

Nonresidential n/a* 1,700 2,500 3,900 6,500

Total 66,900 132,700 168,800 228,400 265,000

% Nonresidential n/a 1.3% 1.5% 1.7% 2.4%

*Information on customer segments was not collected in 1999. 

Source: Bird, L., and K. Cardinal, 2004. Trends in Utility Green Pricing Programs (2003), NREL/TP620-36833. Golden, CO: National Renewable Energy Laboratory, September. 

http://www.eere.energy.gov/greenpower/pdfs/36833.pdf

0

5

10

15

20

25

30

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

0

20

40

60

80

100

120

140

New Programs

Cumulative

Cumulative

137
Table 3.8.4. Customer Participation Rates in Utility Green Pricing Programs 

Participation 

Rate 1999 2000 2001 2002 2003 

Average 0.9% 1.2% 1.3% 1.2% 1.2% 

Median 0.8% 0.7% 0.7% 0.8% 0.9% 

Top 10 programs 2.1%-4.7%* 2.6%-7.3% 3.0%-7.0% 3.0%-5.8% 3.9%-

11.1% 

*Data for April 2000 

Source: Bird and Cardinal, 2004.

Table 3.8.5. Annual Sales of Green Energy through Utility Green Pricing Programs 

(millions of kWh) 

Segment 2000 2001 2002 2003

Residential customers --- 399.7 661.3 874.1

Nonresidential customers --- 172.8 233.7 410.3

All customers 453.7 572.5 895.0 1,284.4

% Nonresidential --- 30% 26% 32%

*Sales information for customer segments not available for 2000. 

Source: Bird and Cardinal, 2004.

138
3.9 – Renewable Energy Certificates 

Renewable energy certificates (RECs)—also known as green tags, renewable energy credits, 

or tradeable renewable certificates—represent the environmental attributes of power 

generated from renewable electric plants. A number of organizations offer green energy 

certificates separate from electricity service (i.e., customers do not need to switch from their 

current electricity supplier to purchase these certificates). Organizations that offer green 

certificate products are listed below. 

Table 3.9.1. Renewable Energy Certificate Product Offerings, July 2004 

Certificate 

Marketer 

Product 

Name 

Renewable 

Resources 

Location of 

Renewable 

Resources 

Residential 

Price 

Premium*

Certification

3 Phases 

Energy Services 

Green 

Certificates 

100%new 

wind 

Nationwide 2.0¢/kWh Green-e 

Aquila, Inc. Aquila Green 

Credits 

(nonresidential 

only) 

100% new 

wind 

Kansas N/A Green-e 

Bonneville 

Environmental 

Foundation 

Green Tags ≥98% new 

wind, ≤ 1% 

new solar, ≤

1% new 

biomass 

Washington, 

Oregon, 

Wyoming, 

Montana, 

Nevada 

2.0¢/kWh Green-e 

Community 

Energy 

New Wind 

Energy 

100% new 

wind 

Pennsylvania, 

West Virginia 

2.5¢/kWh Green-e 

100% Wind 

Renewable 

Energy 

Certificates 

100% new 

wind 

Nationwide 1.5¢/kWh (Green-e for 

nonresidential 

only) 

EAD 

Environmental 

Home Grown 

Hydro 

Certificates 

100% small 

hydro 

(<5MW) 

New England 1.2¢/kWh (Green-e for 

nonresidential 

only) 

Green Mountain 

Energy 

TRCs (nonresidential 

only) 

100% 

renewable 

Nationwide N/A Green-e 

Maine Interfaith 

Power & 

Light/BEF 

Green Tags 

(supplied by 

BEF) 

≥98% new 

wind, ≤ 1% 

new solar, ≤

1% new 

biomass 

Washington, 

Oregon, 

Wyoming, 

Montana, 

Nevada 

2.0¢/kWh 

Green-e 

Maine Interfaith 

Power & Light 

First Wind of 

Maine 

100% wind Maine 4.0¢/kwh — 

Maine Power 

Options 

MPO 

MaineMade 

Certificates 

(nonresidential 

only) 

50% hydro, 

50% 

biomass 

Maine NA — 

139
Mass 

Energy/People’s 

Power and Light 

New England 

Wind 

100% new 

wind 

Massachusetts 5.0¢/kWh — 

Fossil Free 

100% 

Renewable 

100% 

renewable 

Nationwide 2.0¢/kWh Green-e 

Fossil Free 

100% Wind 

100% wind Nationwide 2.5¢/kWh Green-e 

Mainstay 

Energy 

Fossil Free 

100% Solar 

100% solar Nationwide 20¢/kWh Green-e 

WindBuilders 100% new 

wind 

South Dakota 1.0¢/kWh 

$10 per ton 

of CO2 

avoided 

** 

CoolHome New biogas 

and new 

wind 

Vermont and 

Pennsylvania 

(biomass), 

South Dakota 

(wind) 

1.0¢/kWh 

$10 per ton 

of CO2 

avoided 

** 

NativeEnergy 

WindBuilders 

Business 

Partners 

(nonresidential 

only) 

100% new 

wind 

South Dakota 

Minnesota <1.0¢/kWh 

<$10 per 

ton of CO2 

avoided 

** 

NUON 

Renewables 

Ventures 

PVUSA Solar 

TRCs (nonresidential) 

100% solar California NA Green-e 

Pacific 

Renewables, 

Inc 

Green Tags 100% new 

biomass 

Nebraska ~3¢/kWh 

($25/month 

for avg. 

consumer) 

Green-e 

PG&E National 

Energy Group 

PureWind 

Certificates 

100% new 

wind 

New York 4.0¢/kWh — 

Pepco Energy 

Services 

PES Green 

TRC (nonresidential 

only) 

100% new 

renewables 

Nationwide NA Green-e 

PPM Energy Green Tags 

from Wind 

Energy 

(nonresidential 

only) 

100% new 

wind 

Nationwide NA Green-e 

Renewable 

Choice Energy 

American 

Wind 

100% new 

wind 

Nationwide 2.0-

4.0¢/kWh 

Green-e 

140
Sterling Planet Green 

America 

45% new 

wind 

50% new 

biomass 

 

5% new 

solar 

Nationwide 1.6¢/kWh Green-e 

Sun Power 

Electric 

ReGen 

(available in 

New England) 

99% new 

landfill gas, 

1% new 

solar 

New York, 

Massachusetts, 

Rhode Island 

3.6¢/kWh Green-e 

Waverly Light & 

Power 

Iowa Energy 

Tags 

100% wind Iowa 2.0¢/kWh 

— 

WindCurrent Chesapeake 

Windcurrent 

100% new 

wind 

West Virginia 2.5¢/kWh - 

3.0¢/kWh

Green-e 

Viking Wind Green Energy 

Tags 

(nonresidential 

only) 

100% new 

wind 

Minnesota NA Green-e 

Vision Quest Green Energy 

(nonresidential 

only) 

100% new 

wind 

Alberta, 

Canada 

NA Green-e 

*Large users may be able to negotiate price premiums. 

** The Climate Neutral Network certifies the methodology used to calculate the CO2 emissions offset. 

NA = Not applicable. 

Source: L. Bird and B. Swezey, National Renewable Energy Laboratory 

http://www.eere.energy.gov/greenpower/markets/certificates.shtml?page=1

Table 3.9.2. Estimated Wholesale RECs Supplying Voluntary Markets, 2003 

Segment Retail Sales 

Millions of MWh 

Estimated RECs Sales 

Millions of MWh 

Utility Green Pricing 1.3 0.4 

Competitive Markets 1.9 1.9 

Unbundled RECs 0.7 0.7 

Total Green Power Market 3.9 3.0 

Source: L. Bird, NREL, 2004

Table 3.9.3. Voluntary Market REC Retirements in Texas and NEPOOL 

Year Texas Voluntary REC 

Retirements 

(MWh) 

NEPOOL Voluntary REC 

Retirements 

(MWh)* 

2001 N/a 0 

2002 241,000 112,973 

2003 797,000 56,905 

Sources: ERCOT 2004; NEPOOL GIS

141
Table 3.9.4. Voluntary Market Wholesale REC Prices for New Sources by Type and 

Region ($/MWh) 

Region Wind Solar Biomass Small Hydro 

CA 1.75-2.00 1.50

WECC 1.25-7.50 30.00-150.00 1.50-3.50

Central 2.00-5.50 1.50

PJM 15.00-17.00 80.00-200.00 4:00-5.00

New York 15.00-16.00 6.00

NEPOOL 35.00 45.00 5.00

SPP 2.50-5.00

Southeast 3.50

Sources: Evolution Markets (data for July 2003 through October 2004) and GT Energy.

Table 3.9.5. Voluntary Market Wholesale REC Prices for Existing Sources by Type and 

Region ($/MWh) 

Region Biomass Geothermal Hydro Small Hydro LIHI Hydro 

WECC 0.25-2.50 1.00-3.50 

Central 

PJM 

New York 2.00-5.00 2.00-3.00 1.00-3.50 

NEPOOL 2.00-4.00 6.00 

Southeast 

Source: Evolution Markets. Data for July 2003 through October 2004.

142
3.10 – State Incentive Programs 

Many states have policies or programs in place to support renewable energy resources, such 

as tax incentives; industry recruitment incentives; or grant, loan, or rebate programs. The 

following table lists the incentives currently available by state. 

Table 3.10.1. Financial Incentives for Renewable Energy Resources by State 

State Tax Incentives Grants, Loans, Rebates and Other Incentives 

AL Wood-Burning Heating System 

Deduction (Personal) 

Renewable Fuels Development Program (Biomass, 

Municipal Solid Waste) 

AK Power Project Loan Fund 

AZ Qualifying Wood Stove 

Deduction; Solar and Wind 

Energy Systems Credit 

(Personal); Solar and Wind 

Equipment Sales Tax 

Exemption (Personal) 

APS – EPS Credit Purchase Program; TEP – SunShare PV 

Buydown 

AR 

CA Solar or Wind Energy System 

Credit – Personal; Tax 

Deduction for Interest on 

Loans for Energy Efficiency; 

Solar or Wind Energy System 

Credit – Corporate; California 

Property Tax Exemption for 

Solar Systems 

Emerging Renewable (Rebate) Program; SELFGEN – SELFGeneration Program; Solar Schools Program; San Diego - 

Residential Solar Electric Incentive for Homes Destroyed in 

Wildfires; Anaheim Public Utilities – PV Buydown Program; 

Burbank Water & Power – Residential & Commercial Solar 

Support; City of Palo Alto Utilities – PV Partners; Glendale 

Water & Power – Solar Solutions Program; LADWP – Solar 

Incentive Program; Redding Electric – Vantage Renewable 

Energy Rebate Program; Roseville Electric – PV Buy Down 

Program; SMUD – Solar Water Heater Program Rebate; 

SMUD – PV Pioneer II Loan; SMUD – Solar Water Heater 

Program Loan 

Geothermal and PV leasing; Solar water heating; Energy 

technology export program; Agricultural Biomass to Energy 

Program; Supplemental Energy Payments (SEPs) 

CO Aspen Solar Pioneer Program - Solar Hot Water Rebate; 

Gunnison County Electric - Renewable Energy Resource 

Loan; Aspen Solar Pioneer Program - Zero-Interest Loan 

Colorado - Aspen - Grid-Tied Micro Hydro Production 

Incentive; Colorado - Aspen Solar Pioneer Program - PV 

Production Incentive; 

CT Local Option for Property Tax Residential PV Rebate Program; Mainstay Energy Rewards 

Program - Green Tag Purchase Program; Connecticut - 

Commercial, Industrial, Institutional PV Grant Program; 

Connecticut - Fuel Cell Initiative; Connecticut - New Energy 

Technology Program; Energy Conservation Loan 

DE Green Energy Program Rebates; 

DC 

FL Solar Energy Equipment 

Exemption 

Florida - Gainesville Regional Utilities - Solar Rebate 

Program; Florida - JEA - Solar Incentive Program 

GA 

143
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

HI Residential Solar and Wind 

Energy Credit; Corporate Solar 

and Wind Energy Credit 

HECO, MECO, HELCO - Energy $olutions Solar Water 

Heater Rebate; Kauai Electric - Residential Solar Water 

Heating Program; Kaua'i Island Utility Cooperative - 

Commercial Solar Water Heating Program; Oahu - Energy 

$olutions Honolulu Solar Roofs Initiative Loan Program; 

Kauai County - Solar Water Heating Loan Program; Maui 

County - Maui Solar Roofs Initiative Loan Program for Solar 

Water Heating 

ID Solar, Wind, and Geothermal 

Deduction (Personal) 

BEF - Renewable Energy Grant; Low-Interest Loans for 

Renewable Energy Resource Program 

IL Special Assessment for 

Renewable Energy Systems 

Renewable Energy Resources Program Rebates; Chicago 

Photovoltaic Incentive Program (PIP); Renewable Energy 

Resources Program (RERP) Grants; Illinois Clean Energy 

Community Foundation Grants 

IN Renewable Energy Systems 

Exemption 

Alternative Power & Energy Grant Program; Distributed 

Generation Grant Program (DGGP); Energy Education and 

Demonstration Grant Program; Energy Efficiency and 

Renewable Energy (EERE) Set-Aside 

IA Wind Energy Equipment 

Exemption; Local Option 

Special Assessment of Wind 

Energy Devices; Methane Gas 

Conversion Property Tax 

Exemption; Property Tax 

Exemption for Renewable 

Energy Systems 

Grants for Energy Efficiency and Renewable Energy 

Research; Alternate Energy Revolving Loan Program; Iowa 

Building Energy Management Program (Iowa Energy Bank) 

KS Renewable Energy Property 

Tax Exemption 

State Energy Program Grants 

KY 

LA Solar Energy System 

Exemption 

ME Mainstay Energy Rewards Program - Green Tag Purchase 

Program; Renewable Resources Matching Fund Program 

MD Clean Energy Incentive Act 

(Personal Credit); Personal 

Income Tax Credit for Green 

Buildings; Clean Energy 

Incentive Act (Corporate 

Credit); Corporate Income Tax 

Credit for Green Buildings; 

Sales Tax Exemption - Fuel 

Cells; Wood Heating Fuel 

Exemption; Local Option - 

Corporate Property Tax Credit; 

Special Property Assessment 

Solar Energy Grant Program; Community Energy Loan 

Program; State Agency Loan Program 

144
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

MA Alternative Energy and Energy 

Conservation Patent 

Exemption (Personal); 

Renewable Energy State 

Income Tax Credit; Alternative 

Energy and Energy 

Conservation Patent 

Exemption (Corporate); Solar 

and Wind Energy System 

Deduction; Solar and Wind 

Power Systems Excise Tax 

Exemption; Renewable Energy 

Equipment Sales Tax 

Exemption; Local Property Tax 

Exemption 

Clustered PV Installation Program; Open PV Installation 

Program; Mainstay Energy Rewards Program - Green Tag 

Purchase Program; Commercial, Industrial, & Institutional 

Initiative Grants 

MI Community Energy Project Grants; Energy Efficiency Grants; 

Large-Scale PV Demonstration Project Grants; Michigan 

Biomass Energy Program Grants; NextEnergy Curriculum 

Development Grants 

MN Solar-Electric (PV) Sales Tax 

Exemption; Wind Sales Tax 

Exemption; Wind and SolarElectric (PV) Systems 

Exemption 

Solar-Electric (PV) Rebate Program; Solar-Electric (PV) 

Rebate Program; Renewable Development Fund Grants; 

Agricultural Improvement Loan Program for Wind Energy; 

Value-Added Stock Loan Participation Program 

Renewable Energy Production Incentives; 

MS Energy Investment Program 

MO Wood Energy Production 

Credit 

Missouri Schools Going Solar; Energy Loan Program 

MT Residential Alternative Energy 

System Tax Credit; Residential 

Geothermal Systems Credit; 

Alternative Energy Investment 

Corporate Tax Credit; 

Corporate Property Tax 

Reduction for New/Expanded 

Generating Facilities; 

Generation Facility Corporate 

Tax Exemption; Renewable 

Energy Systems Exemption 

NorthWestern Energy - PV Rebate Program; NorthWestern 

Energy - PV Systems for Fire Stations; NorthWestern Energy 

- Sun4Communities; NorthWestern Energy - USB Renewable 

Energy Fund; BEF - Renewable Energy Grant; Alternative 

Energy Revolving Loan Program 

NE Dollar and Energy Savings Loans 

NV Renewable Energy/Solar 

Sales Tax Exemption; 

Renewable Energy Producers 

Property Tax Exemption; 

Renewable Energy Systems 

Exemption 

Solar Energy Systems Demonstration Program; Boulder City 

Public Works - Energy Efficient Appliance Program; Nevada 

Power - PV Rebate Program; Sierra Pacific Power - PV 

Rebate Program 

NH Local Option Property Tax 

Exemption for Renewable 

Energy 

Mainstay Energy Rewards Program - Green Tag Purchase 

Program 

NJ Solar and Wind Energy 

Systems Exemption 

New Jersey Clean Energy Rebate Program; Renewable 

Energy Advanced Power Program; Renewable Energy 

Economic Development Program (REED); Reduced Energy 

Demand Options for Local Governments and Schools 

(REDO) 

145
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

NM Renewable Energy Production 

Tax Credit 

Clean Energy Grants Program 

NY Solar and Fuel Cell Electric 

Generating Equipment Tax 

Credit; Green Building Tax 

Credit Program; Solar and 

Wind Energy Systems 

Exemption 

Energy $mart New Construction Program; PV Incentive 

Program; Wind Incentive Program; LIPA - Solar Pioneer 

Program; Renewables R&D Grant Program; Energy $mart 

Loan Fund 

NC Renewable Energy Tax Credit 

– Personal; Renewable 

Energy Tax Credit – 

Corporate; Active Solar 

Heating and Cooling Systems 

Exemption 

Energy Improvement Loan Program 

ND Geothermal, Solar and Wind 

Personal Credit; Geothermal, 

Solar, and Wind Corporate 

Credit; Large Wind Sales Tax 

Exemption; Geothermal, Solar, 

and Wind Property Exemption; 

Large Wind Property Tax 

Reduction 

OH Conversion Facilities 

Corporate Tax Exemption; 

Conversion Facilities Sales 

Tax Exemption; Conversion 

Facilities Property Tax Exemp. 

Renewable Energy Loans 

OK Zero-Emission Facilities 

Production Tax Credit 

OR Residential Energy Tax Credit; 

Business Energy Tax Credit; 

Renewable Energy Systems 

Exemption 

Solar Electric Buy-down Program; Solar Water Heating Buydown Program; Ashland - Solar Electric Program; Ashland 

Electric Utility - The Bright Way to Heat Water Rebate; EPUD 

- Solar Water Heater Program Rebate; EWEB - Energy 

Management Services Rebate; EWEB - The Bright Way To 

Heat Water Rebate; OTEC - Photovoltaic Rebate Program; 

New Renewable Energy Resources Grants; BEF - 

Renewable Energy Grant; Small Scale Energy Loan Program 

(SELP); Ashland Electric Utility - The Bright Way to Heat 

Water Loan; EPUD - Solar Water Heater Program Loan; 

EWEB - Energy Management Services Loan; EWEB - The 

Bright Way To Heat Water Loan 

PA Sustainable Development Fund Solar PV Grant Program 

(PECO Territory); Pennsylvania Energy Harvest Grant 

Program; Metropolitan Edison Company SEF Grants 

(FirstEnergy Territory); Penelec SEF of the Community 

Foundation for the Alleghenies Grant Program (FirstEnergy 

Territory); SEF of Central Eastern Pennsylvania Grant 

Program (PP&L Territory); Sustainable Development Fund 

Grant Program (PECO Territory); West Penn Power SEF 

Grant Program; Metropolitan Edison Company SEF Loans 

(FirstEnergy Territory); Penelec SEF of the Community 

Foundation for the Alleghenies Loan Program (FirstEnergy 

Territory); SEF of Central Eastern Pennsylvania Loan 

Program (PP&L Territory); Sustainable Development Fund 

Commercial Financing Program (PECO Territory); West 

Penn Power SEF Commercial Loan Program 

146
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

RI Renewable Energy Personal 

Tax Credit; Renewable Energy 

Sales Tax Refund; Renewable 

Energy Property Tax 

Exemption 

PV & Wind Rebate Program; Small Customer Incentive 

Program for Green Power Marketers; Mainstay Energy 

Rewards Program - Green Tag Purchase Program; PV Grant 

for Commercial, Industrial and Institutional Buildings; RFP for 

Purchase/Sale of Renewable Electricity to Large Customers 

Renewable Generation Supply Incentive 

SC 

SD Renewable Energy Systems 

Exemption; Wind Energy 

Property Tax Exemption 

TN Wind Energy Systems 

Exemption 

Small Business Energy Loan Program 

TX Solar Energy Device 

Franchise Tax Deduction; 

Solar and Wind-Powered 

Energy Systems Exemption 

Austin Energy - Home Energy Air Conditioning and 

Appliance Rebates; Austin Energy - Solar Rebate Program 

UT Renewable Energy Systems 

Tax Credit – Personal; 

Renewable Energy Systems 

Tax Credit – Corporate; 

Renewable Energy Sales Tax 

Exemption 

VT Sales Tax Exemption Solar & Wind Incentive Program; Mainstay Energy Rewards 

Program - Green Tag Purchase Program

VA Local Option Property Tax 

Exemption for Solar 

Virginia Small Wind Incentives Program (VSWIP); 

WA Sales and Use Tax Exemption Clallam County PUD - Solar Rebate Program; Grays Harbor 

PUD - Solar Water Heating Rebate; Orcas Power & Light - 

Photovoltaic Rebate; Pacific County PUD - Solar Water 

Heater Rebate; Puget Sound Energy - Solar PV System 

Rebate; BEF - Renewable Energy Grant; Franklin PUD - 

Solar Water Heating Loan; Grays Harbor PUD - Solar Water 

Heating Loan 

WV Tax Exemption for Wind 

Energy Generation; Special 

Assessment for Wind Energy 

Systems 

WI Solar and Wind Energy 

Equipment Exemption 

Focus on Energy - Cash-Back Reward; Wisconsin Municipal 

Utility Solar Energy Cash Allowance; Focus on Energy - 

Grant Programs; Focus on Energy - Loan Program 

WY Renewable Energy Sales Tax 

Exemption 

Photovoltaic Grant Program 

Source: North Carolina Solar Center, Database of State Incentives for Renewable Energy, 

http://www.dsireusa.org/summarytables/financial.cfm?&CurrentPageID=7, July, 2004

147
3.11 – Federal Agency Purchases of Green Power 

In March 2004, federal agency purchases of green power reached 527 million kWh, an 

increase of 70% from July 2003, according to the Federal Energy Management Program 

(FEMP). Including renewable energy generated from on-site systems, the federal government 

uses 1,067 million kWh of renewable energy annually, which puts it more than three-quarters 

of the way toward meeting the 2.5% federal renewable energy usage goal for 2005. The 

federal goal was established by DOE pursuant to Executive Order 13123, which directed 

federal agencies to increase their use of renewable energy. 

148
Table 4.1 – Projections of Renewable Electricity Net Capacity 

(Gigawatts) 

Data Sources Projections 

Renewable Energy 2005 2010 2015 2020 2025

Geothermal AEO2005 - Reference Case 2.19 2.21 2.66 3.45 4.62

AEO2005 - High Renewables 2.21 5.63 7.30

EERE GPRA FY05 6.50 8.20 10.00 12.20

 

Wind AEO2005 - Reference Case 8.18 8.88 9.29 10.45 11.25

AEO2005 - High Renewables 8.88 11.63 13.97

EERE GPRA FY05 14.60 32.30 63.90 67.70

 

Solar1

 AEO2005 - Reference Case 0.61 0.98 1.14 1.60 2.72

AEO2005 - High Renewables 0.99 1.80 3.23

EERE GPRA FY05 2.20 5.20 13.60 26.50

 

Hydroelectric AEO2005 - Reference Case 79.10 79.21 79.21 79.21 79.21

AEO2005 - High Renewables 79.21 79.21 79.21

EERE GPRA FY05 78.90 78.90 78.90 78.90

 

Biomass/Wood 

(excludes cogen) AEO2005 - Reference Case 1.78 1.83 2.06 2.75 4.50

AEO2005 - High Renewables 1.78 2.62 5.18

EERE GPRA FY05 2.10 2.10 2.20 2.70

 

MSW and LFG AEO2005 - Reference Case 3.68 3.83 3.89 3.92 3.93

AEO2005 - High Renewables 3.83 3.96 3.97

EERE GPRA FY052 4.00 4.20 4.40 4.40

 

Total Renewable Energy AEO2005 - Reference Case 100.18 102.09 103.80 107.56 112.99

AEO2005 - High Renewables 102.42 112.37 121.57

EERE GPRA FY053 105.40 116.00 133.90 147.70

Sources: EIA Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February), Tables A16 

and E7. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Projected Benefits of 

Federal Energy Efficiency Programs: FY2005 Budget Request, prepared by the National Renewable Energy 

Laboratory, NREL/TP-620-36407 (May 2004). 

Notes: OnLocation GPRA05 benefits estimates do not estimate any programmatic influence on biomass power 

since the biomass program has been redirected away from biomass power to integrated biorefinery technologies. 

Total represents portfolio case values, while individual program values represent each program case. The 

portfolio case accounts for program interactions and micro-price feedback effects. 

1 Solar thermal and photovoltaic energy. 

2

 EERE does not have an R&D program for Biomass, LFG/MSW and thus are not included in GPRA projections 3 Biomass, MSW and LFG are not included in the portfolio value. The portfolio values do not equal the summed 

values of the individual programs, as the portfolio analysis accounts for program interactions and micro-price 

feedback effects. Total includes biomass combined heat and power and on-site electricity-only plants for 

industrial and commercial sectors not detailed above. 

149
Table 4.2 – Projections of Renewable Electricity Net Generation 

(Billion Kilowatthours) 

 Data Sources Projections 

Renewable Energy 2005 2010 2015 2020 2025

Geothermal AEO2005 - Reference Case 12.07 12.33 16.09 22.83 32.78

 AEO2005 - High Renewables 12.33 41.33 55.65

 EERE GPRA FY05 43.00 57.40 71.80 89.20

 

Wind AEO2005 - Reference Case 23.55 25.89 27.34 31.61 34.52

 AEO2005 - High Renewables 25.89 36.15 44.60

 EERE GPRA FY05 47.10 110.70 234.40 249.80

 

Solar1 AEO2005 - Reference Case 1.08 1.94 2.32 3.35 5.70

 AEO2005 - High Renewables 1.95 3.74 6.73

 EERE GPRA FY05 2.20 8.20 22.20 33.80

 

Hydroelectric AEO2005 - Reference Case 294.17 306.21 306.36 306.62 306.91

 AEO2005 - High Renewables 306.21 306.63 306.91

 EERE GPRA FY05 302.70 303.70 306.90 307.20

 

Biomass/Wood (without 

cogeneration) AEO2005 - Reference Case 20.64 27.61 30.01 32.35 37.35

 AEO2005 - High Renewables 29.58 33.63 44.08

 EERE GPRA FY05 21.40 22.30 22.40 24.50

 

MSW and LFG AEO2005 - Reference Case 26.58 27.82 28.31 28.60 28.73

 AEO2005 - High Renewables 27.82 28.96 29.11

 EERE GPRA FY052

 28.90 30.30 31.30 31.50

 

Total Renewable Energy AEO2005 - Reference Case 408.94 435.54 446.64 465.21 489.19

 AEO2005 - High Renewables 439.72 498.09 541.58

 EERE GPRA FY053

 436.20 483.10 563.30 626.10

 

Sources: EIA Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February), Tables A16 and 

E7. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Projected Benefits of Federal 

Energy Efficiency Programs: FY2005 Budget Request, prepared by the National Renewable Energy Laboratory, 

NREL/TP-620-36407 (May 2004). 

Notes: OnLocation GPRA05 benefits estimates do not estimate any programmatic influence on biomass power 

since the biomass program has been redirected away from biomass power to integrated biorefinery technologies. 

Total represents portfolio case values, while individual program values represent each program case. The portfolio 

case accounts for program interactions and micro-price feedback effects. 

1 Solar thermal and photovoltaic energy. 

2

 EERE does not have an R&D program for LFG/MSW and thus are not included in GPRA projections 

3 Biomass, MSW and LFG are not included in the portfolio value. The portfolio values do not equal the summed 

values of the individual programs, as the porfolio analysis accounts for program interactions and micro-price 

feedback effects. 

150
Table 4.3 – Projections of Renewable Electricity Carbon Dioxide 

Emissions Savings 

(Million Metric Tons Carbon Equivalent per Year)

 

 Data Sources Projections 

 2005 2010 2015 2020 2025

Renewable Energy 

Geothermal AEO2005 - Reference Case 2.32 2.45 2.97 3.75 5.03

 AEO2005 - High Renewables 2.45 6.79 8.54

 EERE GPRA FY05 8.54 10.60 11.80 13.68

 

Wind AEO2005 - Reference Case 4.53 5.14 5.05 5.19 5.30

 AEO2005 - High Renewables 5.14 5.94 6.84

 EERE GPRA FY05 9.35 20.45 38.52 38.32

 

Solar1 AEO2005 - Reference Case 0.21 0.39 0.43 0.55 0.87

 AEO2005 - High Renewables 0.39 0.61 1.03

 EERE GPRA FY05 0.44 1.51 3.65 5.18

 

Hydroelectric AEO2005 - Reference Case 56.63 60.82 56.59 50.39 47.08

 AEO2005 - High Renewables 60.82 50.39 47.08

 EERE GPRA FY05 60.12 56.10 50.43 47.12

 

Biomass/Wood (without 

cogeneration) AEO2005 - Reference Case 3.97 5.48 5.54 5.32 5.73

 AEO2005 - High Renewables 5.88 5.53 6.76

 EERE GPRA FY05 4.25 4.12 3.68 3.76

 

MSW and LFG AEO2005 - Reference Case 5.12 5.53 5.23 4.70 4.41

 AEO2005 - High Renewables 5.53 4.76 4.47

 EERE GPRA FY052

 5.74 5.60 5.14 4.83

 

Total Renewable Energy AEO2005 - Reference Case 78.72 86.51 82.50 76.45 75.04

 AEO2005 - High Renewables 87.34 81.85 83.08

 EERE GPRA FY053

 86.64 89.23 92.57 96.04

 

Heat Rate Btu/kWh 10,796 10,593 9,019 8,266 7,891 

Carbon Coefficient MMTCE/Tbtu 0.01783 0.01875 0.02048 0.01988 0.01944

Sources: Generation data: EIA Annual Energy Outlook 2005, DOE/EIA-0383 (04) (Washington, D.C., 

February 2005), Tables A16 and F8. U.S. Department of Energy, Office of Energy Efficiency and Renewable 

Energy, Projected Benefits of Federal Energy Efficiency Programs: FY2005 Budget Request, prepared by the 

National Renewable Energy Laboratory, NREL/TP-620-36407 (May 2004).

Carbon emission coefficients and heat rates: U.S. Department of Energy, GPRA2003 Data Call, Appendix B, 

pages B-13 and B-16, (September 14, 2001). 

151
Notes:

Carbon Emissions Savings based on calculation: (10^9 kWh) * (Btu/kWh) * (TBtu/10^12 Btu) * (MMTCE/TBtu)

1 Solar thermal and photovoltaic energy. 

2

 EERE does not have an R&D program for LFG/MSW and thus are not included in GPRA projections 

3 Biomass, MSW and LFG are not included in the portfolio value. The portfolio values do not equal the 

summed values of the individual programs, as the portfolio analysis accounts for program interactions and 

micro-price feedback effects. 

152
Table 5.1 – U.S. Primary and Delivered Energy – Overview 

(Quadrillion Btu per year)

1980 1990 2000 2001 2002 2003 2010 

Primary Consumption by Source 1

Petroleum 2 34.20 33.55 38.40 38.33 38.40 39.07 44.84 

Natural Gas 20.39 19.74 23.91 22.90 23.65 22.51 26.11 Coal3 15.39 19.18 22.65 21.98 22.04 22.76 24.95 

Nuclear 2.74 6.10 7.86 8.03 8.14 7.97 8.49 Renewable4 5.49 6.13 6.16 5.29 5.96 6.15 6.85 

Other 5 0.07 -0.03 0.06 -0.01 -0.01 -0.07 0.00 

Total Primary 78.29 84.68 98.90 96.37 98.01 98.16 111.27 

Primary Consumption by Sector

Residential 15.85 17.04 20.51 20.25 20.94 21.23 23.47 Commercial 10.59 13.32 17.16 17.32 17.57 17.55 20.29 Industrial 32.15 31.89 34.68 32.53 32.86 32.52 35.47 Transportation 19.70 22.42 26.55 26.28 26.65 26.86 32.04 Total Primary6 78.29 84.67 98.90 96.38 98.03 98.16 111.27 

Delivered Consumption by Sector

Residential 7.50 6.60 7.20 6.91 6.95 7.24 12.67 Commercial 4.10 3.85 4.22 4.04 4.12 4.18 9.53 Industrial 22.67 21.21 22.80 21.83 22.13 21.69 27.35 Transportation 19.66 22.37 26.49 26.22 26.60 26.80 31.85 Total Delivered6 53.93 54.03 60.71 59.00 59.79 59.91 81.39 

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table A2; EIA, 

Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Tables 2.1a-f.

Notes: 

1 For historical figures, these values include the electric-power sector's consumption 2 Includes natural gas plant liquids, crude oil consumed as a fuel, and non-petroleum-based liquids for blending, such as ethan3 Includes coal in all sectors as well as net imports of coal coke in the industrial sector 

153
4 Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste

photovoltaic and solar thermal sources; nonelectric energy from renewable sources, such as active and passive solar systems

ethanol and gasoline components of E85, but not the ethanol components of blends less than 85 percent. Excludes electricity 

sources and nonmarketed renewable energy. 

5 For historical figures, this value includes hydroelectric pumped storage and electricity net imports. For forecasted figures, thi

liquid hydrogen. 

6 For historical figures, this value does not include the electric-power sector's consumption 

154
Table 5.2 – Electricity Flow Diagram (Quadrillion Btu) 

Source: EIA, Annual Energy Review, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Diagram 5. Notes: a Blast furnace gas, propane gas, and other manufactured waste gases derived from fossil fuels. b Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies. c Pumped storage facility production minus energy used for pumping. d Approximately two-thirds of all energy used to generate electricity. See note “Electrical System Energy Losses,” at end of Section 2. e Data collection frame differences and nonsampling error.f Electric energy used in the operation of power plants, estimated as 5 percent of gross generation. See note “Electrical System Energy Losses,” at end of Section 2.

g Transmission and distribution losses (elecoccur between the point of generation and delivery to the customer) arpercent of gross generation. See note “Electrical System Energy Losses,” at h Commercial retail sales plus approximate“Other” retail sales from Table 8.9. I Approximately 5 percent of “Other” retail sj Commercial and industrial facility use of ongeneration; and electricity sales among adjacent or co-located facilities for winformation is not available. 

155
Table 5.3 – Electricity Overview 

 (Billion Kilowatthours, unless otherwise noted) 

1980 1990 2000 2001 2002 2003 20

Electric Power Sector Generation 1 2,286 2,901 3,638 3,580 3,698 3,691 4,2

End-Use Sector Generation 3 137 165 157 160 157 Total Generation 2,290 3,038 3,802 3,737 3,858 3,848 4,3

Capability (gigawatts)  Electric Power Sector 2 579 710 782 819 876 923 9

 End Use Sector 3 NA 24 30 29 29 30 

 Total Capability 579 734 812 848 905 953 9

Imports from Canada/Mexico 25 18 49 39 36 30 Exports to Canada/Mexico 4 16 15 16 14 24 Loss and Unaccounted for 4 216 214 231 215 241 179 

Retail Sales 5 2,094 2,713 3,421 3,370 3,463 3,500 4,0

Direct Use 6 NA 114 183 174 178 175 2

Total Use 2,094 2,827 3,605 3,544 3,641 3,675 4,2

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Tables A8, A9 and A10Review 2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Tables 8.1, 8.11a, 8.11b, and 8.11d. 

Notes: 

1 Electricity-only and combined-heat-and-power (CHP) plants within the NAICS 22 category whose primary business is to sell el

heat, to the public. Through 1988, data are for electric utilities only; beginning in 1989, data are for electric utilities and independ

2 Through 1988, data are for net summer capacity at electric utilities only. Beginning in 1989, data also include net summer capa

producers, commercial plants, and industrial plants. All data include electric sector combined-heat-and-power (CHP) plants beg

3 Commercial and industrial combined-heat-and-power (CHP) and electricity-only plants. Data begins in 1989. 4 Electricity losses that occur between the point of generation and delivery to the customer, and data collection frame difference5 Electricity retail sales to ultimate customers reported by electric utilities and other energy service providers. 6 Commercial and industrial facility use of onsite net electricity generation; and electricity sales among adjacent or co-located fa

information is not available. 

156
Table 5.4 - Consumption of Fossil Fuels by Electric Generators

1980 1990 2000 2001 2002 2003 201

Coal (million short tons) 1 569 781 983 962 975 1,002 1,13

Distillate Fuel Oil (million barrels) 2 29 16 30 29 22 28 6

Residual Fuel Oil (million barrels) 3 391 183 138 159 105 137 13

Petroleum Coke (million short tons) 0.2 1.0 3.2 3.3 5.7 5.7 NOther Liquids (million barrels) 4 NA 0.02 0.4 0.4 1.2 1.9 N

Total Petroleum (million barrels) 5 421 205 184 205 156 196 20

Natural Gas (billion cubic feet) 3,682 3,147 5,014 5,142 5,408 4,688 6,74

Stocks of Coal and Petroleum (end of year)

Coal (million short tons) 183 156 102 138 142 121 NPetroleum (million barrels) 7 136 84 41 57 52 52 N

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Tables A2, A13 

Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.5b and 8.8.

Notes:

Data is for electric power sector consumption only. Data include fuel consumption to produce electricity by combined hea

Through 1988, consumption data are for electric utilities only. Beginning in 1989, consumption data also include independ

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 2 Light fuel oil (nos. 1, 2, and 4). For 1949-1979, data are for gas turbine and internal combustion plant use of petroleum. 

 For 1980-2000, electric utility data also include small amounts of kerosene and jet fuel. Forecast values calculated from q

Btu using conversion factor 5.825 MMBtu/barrel. 

3 Heavy fuel oil (nos. 5 and 6). For 1949-1979, data are for steam plant use of petroleum. 

For 1980-2000, electric utility data also include a small amount of fuel oil no. 4. Forecast values calculated from quadrillio

Btu using conversion factor 6.287 MMBtu/barrel. 

4 Jet fuel, kerosene, other petroleum liquids, and waste oil. 5 Petroleum coke is converted from short tons to barrels by multiplying by 5. In forecasted values, total petroleum is calcu6 Through 1998, data are for electric utilities only. Beginning in 1999, data are for electric utilities and independent power 7 Includes distillate fuel oil, residual fuel oil, other liquids and petroleum coke. 

157
Table 5.5 – Electric Power Sector Energy Consumption 

(Trillion Btu) 

1980 1990 2000 2001 2002 2003 2010 

Coal 12,123 16,235 20,185 19,494 19,733 20,419 22,812 2Natural Gas 3,810 3,224 5,120 5,271 5,522 4,805 6,874 

Petroleum 2,634 1,281 1,145 1,270 955 1,200 1,263 

Other Gas 1 NA 6 19 9 25 13 NA 

Total Fossil Fuels 18,567 20,746 26,470 26,044 26,235 26,437 30,949 3

Nuclear Electric Power 2,739 6,104 7,862 8,033 8,143 7,973 8,490 

Hydroelectric Pumped Storage 2 --- -36 -57 -90 -88 -88 NA 

Conventional Hydroelectric 2,867 3,014 2,768 2,169 2,636 2,722 3,084 

Wood 3 106 126 116 141 152 323 Waste 2 180 294 314 353 336 344 Geothermal 110 326 296 289 305 276 271 Solar 3 NA 4 5 6 6 5 11 

Wind NA 29 57 68 105 108 266 Total Renewable Energy 2,982 3,658 3,547 2,962 3,545 3,600 4,299 

Electricity Imports 71 8 115 75 78 22 31 Other 4 NA 0.08 1.28 0.00 6.96 1.37 NA 

Total Primary Consumption 24,359 30,481 37,939 37,024 37,919 37,945 43,769 4

Sources: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.4b and EIA, 

2005, DOE/EIA-0383 (20045 (Washington, D.C., February 2005), Tables A2 and A17. Notes:

Data are for fuels consumed to produce electricity at both electricity-only and at combined heat and power plants. Through 19

at electric utilities only. Beginning in 1989, data also include consumption at independent power producers. 

158
1 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 

2 Pumped storage facility production minus energy used for pumping. 1980 data included in Conventional Hydroelectric. 3 Solar thermal and photovoltaic energy. 4 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies. 

NA = Not Available 

159
Table 5.6 – Fossil Fuel Generation by Age of Generating Units 

(Megawatts) 

1980 1990 2000 2001 2002 2003 2004

 

<5 years 91,001 39,870 54,274 90,877 155,534 204,504 218,854 

6-10 years 136,236 54,270 44,042 42,164 37,735 33,121 33,234 

11-20 years 145,618 224,879 92,854 87,057 82,977 83,140 81,085 

21-30 years 99,223 143,868 221,690 210,982 196,464 175,461 156,694 

31-40 years 21,042 93,450 141,055 155,292 172,139 188,274 205,136 

41-50 years 4,023 14,701 86,582 91,321 94,204 95,560 93,156 

>50 years 4,232 2,566 11,634 15,259 18,161 24,487 33,967 

Total 501,376 573,603 652,129 692,952 757,214 804,546 822,128 

 

Source: PowerDat, © 2005, Platts, a division of the McGraw-Hill companies. Query by NREL 3/05.

Notes: 

Total MW does not equal fossil fuel-generation capacity cited in Table 6.1. 

Capacity reported in this table is nameplate capacity 

160
Table 5.7 – Nuclear Generation by Age of Generating Units 

(Megawatts) 

1980 1990 2000 2001 2002 2003 2004

 

<5 years 16,289 30,408 1,270 0 0 0 0

6-10 years 33,989 25,628 1,215 2,485 2,485 1,270 1,270

11-20 years 6,413 48,929 56,036 51,537 49,189 47,200 40,278

21-30 years 309 6,073 44,597 46,859 43,105 41,420 39,315

31-40 years 0 0 4,095 6,332 12,435 17,324 26,351

Total 57,000 111,039 107,214 107,214 107,214 107,214 107,214

Source: PowerDat, © 2005, Platts, a division of the McGraw-Hill companies. Query by NREL 3/05.

Notes: 

Total MW does not equal nuclear generation capacity cited in Table 6.1. 

Capacity reported in this table is nameplate capacity 

161
Table 5.8 – Operational Renewable Energy Generating Capacity 

(Megawatts) 

1980 1990 2000 2001 20

Agricultural Residues2 40 165 373 373 3

BioGas3 18 361 933 999 1,0

Municipal Solid Waste4 263 2,172 2,970 2,970 2,9

Timber Residues5 3,576 6,305 7,447 7,458 7,4

Bioenergy Total 6 3,897 9,003 11,722 11,800 11,8

Geothermal 802 2,540 2,779 2,779 2,7Photovoltaic 7 0.025 4.170 27.645 38.452 59.7

Solar Thermal 0 274 354 354 3Hydro 8 80,491 90,955 94,324 94,335 94,3

Wind 0.06 1,569 2,780 4,623 5,0Total 85,190 104,344 111,987 113,930 114,4Source: Renewable Electric Plant Information System (REPiS Database), Version 7, National Renewable Energy Laborat

http://www.nrel.gov/analysis/repis/.Notes: 

Totals do not equal renewable generation capacity cited in Table 6.1. 12003 data is preliminary; it is not verified at time of Data Book release 2Agricultural residues, cannery wastes, nut hulls, fruit pits, nut shells 3Biogas, alcohol (includes butahol, ethanol, and methanol), bagasse, hydrogen, landfill gas, livestock manure, wood gas (f4Municipal solid waste (includes industrial and medical), hazardous waste, scrap tires, wastewater sludge, refused-derived 5Timber and logging residues (Includes tree bark, wood chips, saw dust, pulping liquor, peat, tree pitch, wood or wood was6 There are an additional 65.45 MW of ag waste, 5.445 MW of bio gas, and 483.31 MW of wood residues that are 

not accounted for here because they have no specific online date. 7 There are an additional 3.4 MW of photovoltaic capacity that are not accounted for here because they have no specific on

8 There are an additional 24 MW of hydroelectric capacity that are not accounted for here because they have no specific o

162
Table 5.9 – Number of Utilities by Class of Ownership and Nonutilities 

1980 1990 1999 2000 2002 2003

Investor Owned Utilties 240 266 239 240 217 219Federally Owned Utilities 41 10 9 9 12 12Cooperatively Owned Utilities1 936 951 900 894 889 895Other Publicly Owned Utilities 1,753 2,010 2,012 2,009 1,870 1,886Total Number of Utilities 2,970 3,237 3,160 3,152 2,988 3,012Nonutilities 1,930 511 617Source: EIA, The Changing Structure of the Electric Power Industry 2000: An Update; UDI/Platts Energy, Platts director

electric power producers and distributors 109th edition, The McGraw-Hill Companies. 

Notes: 

1 Co-ops operate in all states except Connecticut, Hawaii, Rhode Island, and the District of Columbia Note: 2001 data is not reported, but is available from the publishers (Platts) 

163
Table 5.10 – Top 10 Investor-Owned Utilities 

Utility by Sales (Million kWh) 1990 2000 2001 2002 

 Rank Million kWh Rank Million kWh Rank Million kWh Rank Million k

Florida Power & Light Co. 5 65,222 2 88,128 2 90,495 1 95,TXU Electric Co. 1 78,340 1 100,885 1 102,526 2 90,Georgia Power Co. 8 53,953 4 74,434 5 72,545 3 75,4Duke Energy Corp 7 58,359 9 53,726 4 72,977 4 75,Virginia Electric & Power Co. 9 52,122 8 65,294 7 67,858 6 71,4Commonwealth Edison Co. 2 70,852 3 77,176 3 76,918 5 73,Southern California Edison Co. 4 70,063 6 73,686 8 52,034 7 54,Alabama Power Co. 12 38,081 10 52,068 9 49,338 8 52,PacifiCorp 10 40,288 43 18,859 11 47,708 11 47,Pacific Gas & Electric Co. 3 70,597 7 72,121 12 46,680 9 49,Detroit Edison Co 11 39,674 11 50,131 10 48,089 10 48,Reliant Energy HL&P 6 58,583 5 73,716 6 69,839 16 35,4

Utility by Revenue (Million $) 1990 2000 2001 2002 

Rank Million $ Rank Million $ Rank Million $ Rank Millio

Florida Power & Light Co. 4 4,803 4 6,065 3 7,302 2 7,Southern California Edison Co. 1 6,767 1 7,416 1 7,782 1 7,TXU Electric Co. 6 4,200 3 6,433 2 7,748 4 6,Pacific Gas & Electric Co. 2 6,513 2 6,988 4 7,171 3 6,Consolidated Edison Co-NY Inc. 5 4,385 6 5,286 6 5,622 6 4,Commonwealth Edison Co. 3 5,668 5 5,723 5 5,703 5 5,4Virginia Electric & Power Co. 10 3,299 9 4,022 7 4,340 7 4,

164
Duke Energy Corp 7 3,681 12 3,151 9 4,159 8 4,

Georgia Power Co. 9 3,426 8 4,283 8 4,305 9 4,Public Service Electric&Gas Co. 11 3,262 11 3,247 11 3,563 10 3,6Reliant Energy HL&P 8 3,436 7 4,743 10 5,622 14 2,8Detroit Edison Co. 12 3,187 10 3,834 12 3,511 11 3,4Source: EIA, Electric Sales and Revenue, DOE/EIA -0540 (00) (Washington, D.C., December 2003), Table 17. 

165
Table 5.11 – Top 10 Independent Power Producers Worldwide 

(Megawatts) Company 2002 Capacity (MW) 2003 Capacity (MW)Tractebel Electricity & Gas Int'l 50,000 48,317 ENEL SpA. 46,456 45,744 AES 55,660 44,917 Entergy Wholesale Operations 21,323 30,000 Calpine 19,319 29,891 Dominion Generation 23,830 24,408 Mirant 22,100 23,254 NRG Energy 20,954 21,200 Reliant 22,349 19,442 Edison Mission Energy 18,688 18,733 Source: Company 10K SEC filings at http://www.sec.gov/ accessed 7/04 

166
Table 5.12 – Utility Mergers and Acquisitions 

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 

Mergers/Acquisitions 

IOU-IOU 4 1 2 1 7 4 1 3 1 5 10 4 10 3 Co-op-Co-op 4 3 2 2 7 2 1 4 2 13 15 15 3 3 IOU-Co-op 1 2 1 1 

IOU-Gas 1 154361 

Muni-Muni 1 2 

Muni-Co-op 1 1 

Power Authority-IOU 1

Nonutility-IOU 6 1 

Nonutility-Muni 

Foreign-IOU 2 2 1 3 

Total 8 4 4 4 16 6 2 9 4 25 30 26 27 

Related Activities Name Changes 5 2 7 11 1 4 

New Holding Company 15423 

Moved Headquarters 1

Ceased Operations 1 

Source: Calculated from UDI/Platts Energy, Platts directory of electric power producers and distributors 109th

edition, The McGraw-Hill Companies

Notes:

1 Gas local distribution company, pipeline, or developer 2 Excludes Canadian mergers and acquisitions. Includes foreign acquisition of U.S. companies 

167
Table 5.13a – North American Electric Reliability Council Map for the United Sta

ECAR ECAR East Central Area Reliability 

Coordination Agreement 

NPCC Northeast Power Coordinating Coun

ERCOT Electric Reliability Council of Texas SERC Southeastern Electric Reliability Co

FRCC Florida Reliability Coordinating Council SPP Southwest Power Pool MAAC Mid-Atlantic Area Council WECC Western Electricity Coordinating CoMAIN Mid-Atlantic Interconnected Network ASCC Alaskan Systems Coordinating Cou

MAPP Mid-Continent Area Power Pool 

Source: North American Electric Reliability Council, www.nerc.com

168
Table 5.13b – Census Regions 

 Source: U.S. Department of Commerce, Bureau of the Census, www.census.gov

169
170
Table 6.1 – Electric Net Summer Capability (All Sectors)

(Gigawatts)  1980 1990 2000 2001 2002 2003 20

 Coal 1 NA 307.4 315.1 314.2 315.4 315.4 313

 Petroleum/Natural Gas 2 NA 220.4 283.8 320.7 374.2 421.3 448

Total Fossil Energy 444.1 527.8 598.9 634.9 689.5 736.7 762Nuclear 51.8 99.6 97.9 98.2 98.7 98.8 100Hydroelectric Pumped Storage 3 NA 19.5 19.5 19.1 20.4 20.4 20

 Conventional Hydroelectric 81.7 73.9 79.4 79.5 79.4 79.4 79 Geothermal 0.9 2.7 2.8 2.2 2.3 2.3 2 Wood 4 0.1 5.5 6.1 5.9 5.8 5.9 7

 Waste 5 NA 2.5 3.9 3.8 3.8 3.9 3

 Solar Thermal and Photovoltaic NA 0.3 0.4 0.4 0.4 0.4 1 Wind NA 1.8 2.4 3.9 4.4 4.9 8Total Renewable Energy 82.7 86.8 94.9 95.7 96.1 96.7 102

Other 6 NA 0.5 0.5 0.4 0.6 0.6 0

Total Electric Capability 578.6 734.1 811.7 848.3 905.3 953.2 986

Sources: EIA, Annual Energy Outlook 2005 DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Tables A9, A16; EIA, 

2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.11a. 

Notes:Data include electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity, or elect

public. Through 1988, data are for net summer capacity at electric utilities only. Beginning in 1989, data also include net summ

independent power producers and the commercial and industrial (end-use) sectors. 

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.2 Petroleum, natural gas, distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, waste oil, s

blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. Includes natural gas fired 

3 Pumped storage included in Conventional Hydro prior to 1989. 4 Wood, black liquor, and other wood waste. Includes projections for energy crops after 2010. Includes other biomass in proje5 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. Waste included in Wood p6 Includes batteries, chemicals, hydrogen, pitch, sulfur, purchased steam, fuel cells, and miscellaneous technologies. 

NA = Not Available 

171
Table 6.2 – Electricity-Only Plant Net Summer Capability

(Gigawatts) 

1980 1990 2000 2001 2002 2003 2010 

 Coal 2 NA 299.9 305.2 305.2 305.8 305.5 304.6 

 Petroleum/Natural Gas 3 NA 198.7 243.9 279.4 324.6 370.3 388.8 

Total Fossil Energy NA 498.6 549.0 584.5 630.4 675.8 693.4 Nuclear NA 99.6 97.9 98.2 98.7 98.8 100.6 Hydroelectric Pumped Storage 4 NA 19.5 19.5 19.1 20.4 20.4 20.9 

 Conventional Hydroelectric NA 73.3 78.2 78.4 78.3 78.3 78.2  Geothermal NA 2.7 2.8 2.2 2.3 2.3 2.2  Wood 5 NA 1.0 1.5 1.5 1.4 1.4 1.8 

 Waste 6 NA 1.9 2.8 3.0 2.9 3.0 3.6 

 Solar Thermal and Photovoltaic NA 0.3 0.4 0.4 0.4 0.4 0.6  Wind NA 1.8 2.4 3.6 4.4 4.9 8.9 Total Renewable Energy NA 80.9 88.1 89.1 89.7 90.2 95.3 

Other NA 0.0 0.0 0.0 0.0 0.0 0.0 Total Electric Capability 7 NA 698.6 754.5 790.8 839.2 885.2 910.1 

Sources: EIA, Annual Energy Outlook 2005 DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Tables A9, A16; E

Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.11c. 

Notes:Data are for electricity-only plants in the electric power sector whose primary business is to sell electricity to the public. Th

for net summer capacity at electric utilities only. Beginning in 1989, data also include net summer capacity at independent 

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 2 Petroleum, natural gas, distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, waste oil, s

fuels, blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. Includes natura

generation.

3 Pumped storage included in Conventional Hydro prior to 1989. 4 Wood, black liquor, and other wood waste. Includes projections for energy crops after 2010. Includes other biomass in p5 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. Waste included in Wo6 Includes batteries, chemicals, hydrogen, pitch, sulfur, purchased steam, fuel cells, and miscellaneous technologies. 

NA = Not Available 

172
Table 6.3 – Combined-Heat-and-Power Plant Net Summer Capability

(Gigawatts) 

1980 1990 2000 2001 2002 2003 2010 202

 Coal 2 NA 2.4 5.0 4.6 5.2 5.7 5.1 5

 Petroleum/Natural Gas 3 NA 8.3 21.9 22.5 30.8 31.5 39.7 39

Total Fossil Energy NA 10.7 26.9 27.1 36.1 37.2 44.8 44Nuclear NA NA NA NA NA NA NA NHydroelectric Pumped Storage NA NA NA NA NA NA NA N Conventional Hydroelectric NA 0.0 0.0 0.0 0.0 0.0 0.00 0.0 Geothermal NA 0.0 0.0 0.0 0.0 0.0 0.00 0.0 Wood 4 NA 0.2 0.2 0.1 0.1 0.2 0.00 0.0

 Waste 5 NA 0.2 0.5 0.4 0.4 0.4 0.00 0.0

 Solar Thermal and Photovoltaic NA NA NA NA NA NA 0.00 0.0 Wind NA 0.0 0.0 0.3 0.0 0.0 NA NTotal Renewable Energy NA 0.5 0.7 0.8 0.6 0.6 0.3 0Other NA 0.0 0.0 0.0 0.0 0.0 0.0 0Total Electric Capability 6 NA 11.2 27.7 27.9 36.6 37.8 45.1 45

Sources: EIA, Annual Energy Outlook 2005 DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Tables A9, A

Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.11c.Notes:Includes combined-heat-and-power (CHP) plants whose primary business is to sell electricity and heat to the public. F

does not include electric utility CHP plants—these are included in "Electricity-Only Plant Capability " in Table 6.2. Also 

commercial and industrial CHP and a small number of commercial electricity-only plants. 

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.2 Petroleum, natural gas, distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, waste 

supplemental gaseous fuels, blast furnace gas, propane gas, and other manufactured and waste gases derived from 

Includes natural gas fired distributed generation. 

3 Pumped storage included in Conventional Hydro prior to 1989. 4 Wood, black liquor, and other wood waste. Includes projections for energy crops after 2010. Includes other biomass 

projections. 5 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. Waste included in 

1985. 

6 Includes batteries, chemicals, hydrogen, pitch, sulfur, purchased steam, fuel cells, and miscellaneous technologies. 

NA = Not Available 

173
Table 6.4 – Regional Noncoincident 1 Peak Loads 

(Megawatts, except as noted) North American Electric Reliability Council Regions 1990 2000 2001 2002 2003 1990 2000 20

Summer Peak Winter P

ECAR 79,258 92,033 100,235 102,996 100,714 67,097 84,546 85,4ERCOT 42,737 57,606 55,201 56,248 57,639 35,815 44,641 44,0FRCC NA 37,194 39,062 40,696 41,618 NA 38,606 40,92MAAC 42,613 49,477 54,015 55,569 56,257 36,551 43,256 39,4MAIN 40,740 52,552 56,344 56,396 57,169 32,461 41,943 40,52MAPP (U.S.) 24,994 28,605 28,321 29,119 29,957 21,113 24,536 21,8NPCC (U.S.) 44,116 50,057 55,949 56,012 56,550 40,545 43,852 42,6SERC 121,943 156,088 149,293 158,767 157,864 117,448 139,146 135,1SPP 52,541 40,199 40,273 39,688 40,564 38,949 30,576 29,6WECC2 (U.S.) 97,389 114,602 109,119 119,074 119,320 94,252 97,324 96,62Contiguous U.S. 546,331 678,413 687,812 714,565 717,652 484,231 588,426 576,3ASCC (Alaska) 463 NF NF NF NF 613 NF NHawaii NF NF NF NF NF NF NF NU.S. Total 546,794 678,413 687,812 714,565 717,652 484,844 588,426 576,3Capacity Margin (%) 3 21.6 15.7 14.5 16.4 19.8 NA 29.5 28

Source: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.12.

Notes: 

NF = data not filed NA = Not Applicable 2003 data are forecast estimates. 

1 Noncoincident peak load is the sum of two or more peak loads on individual systems that do not occur at the same time 2 Renamed from WSCC in 2002 3 The percent by which planned generating capacity resources are expected to be greater (or less) than estimated net inte

of expected peak summer (or winter) demand. Net internal demand does not include estimated demand for direct control 

customers with interruptible service agreements.

174
Table 6.5 – Electric Generator Cumulative Additions and Retirements 

(Gigawatts) 1 

 

2010 2020 2025 

 

Cumulative Planned Additions 

Coal Steam 1.8 1.8 1.8 

Other Fossil Steam 2 0.0 0.0 0.0 

Combined Cycle 28.3 28.3 28.3 

Combustion Turbine/Diesel 3.9 3.9 3.9 

Nuclear 0.0 0.0 0.0 

Pumped Storage 0.0 0.0 0.0 

Fuel Cells 0.0 0.0 0.0 

Renewable Sources 3 2.7 2.9 3.0 

Distributed Generation 4 0.0 0.0 0.0 

Total Planned Additions 36.7 36.9 37.0 

 

Cumulative Unplanned Additions 

Coal Steam 0.0 30.6 85.1 

Other Fossil Steam 2 0.0 0.0 0.0 

Combined Cycle 3.5 44.2 56.8 

Combustion Turbine/Diesel 5.9 47.4 69.9 

Nuclear 0.0 0.0 0.0 

Pumped Storage 0.0 0.0 0.0 

Fuel Cells 0.0 0.0 0.0 

Renewable Sources 3 0.2 4.0 7.7 

Distributed Generation 4 0.4 3.1 6.9 

Total Unplanned Additions 9.9 129.1 226.4 

 

Cumulative Retirements 

Coal Steam 2.4 3.0 3.0 

Other Fossil Steam 2 9.3 28.6 29.2 

Combined Cycle 0.1 0.4 0.4 

Combustion Turbine/Diesel 1.9 8.1 9.9 

Nuclear 0.0 0.0 0.0 

Pumped Storage 0.0 0.0 0.0 

Fuel Cells 0.0 0.0 0.0 

Renewable Sources 3 0.1 0.1 0.1 

Total Retirements 13.8 40.1 42.6 

 

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) 

(Washington, D.C., February 2005), Table A9.

Notes: 

1

 Additions and retirements since December 31, 2001. 2

 Includes oil-, gas-, and dual-fired capability. 3

 Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid 

waste, landfill gas, other 

biomass, solar, and wind power. 4

 Primarily peak load capacity fueled by natural gas. 

175
Table 6.6 – Transmission and Distribution Circuit Miles

(Miles) 1

Voltage 

(kilovolts) 1980 1990 1999 2000 2 2001 2 2002 2 2003 2

 

230 NA 70,511 76,762 76,437 80,515 81,252 82,238

345 NA 47,948 49,250 51,025 53,855 54,827 54,195

500 NA 23,958 26,038 25,000 27,343 27,587 27,407

765 NA 2,428 2,453 2,426 2,518 2,560 2,560

Total NA 144,845 154,503 154,888 164,231 166,226 166,400

Sources: EIA, Electricity Transmission Fact Sheets, 

http://www.eia.doe.gov/cneaf/electricity/page/fact_sheets/transmission.html; NERC, Electricity Supply 

and Demand Database, 2003, http://www.nerc.com/~esd/Brochure.pdf

Notes:

1

 Circuit miles of AC lines 230 kV and above. 

2

 Data includes both existing and planned transmission lines 

176
Table 7.1 – Electricity Net Generation

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2010 2020 2025

 

 Coal 1

 1,162 1,594 1,966 1,904 1,933 1,970 2,223 2,494 2,890 

 Petroleum 2

 246 127 111 125 95 118 126 143 148 

 Natural Gas 3

 346 373 601 639 691 629 922 1,374 1,403 

 Other Gases 4

 N/A 10 14 9 11 11 4 5 5 

Total Fossil Energy 1,754 2,104 2,692 2,677 2,730 2,729 3,276 4,016 4,446

Nuclear 251 577 754 769 780 764 813 830 830 

Hydroelectric Pumped Storage5

 N/A -4 -6 -9 -9 -9 -9 -9 -9 

 Conventional Hydroelectric 6

 279 293 276 217 264 275 306 307 307

 Geothermal 5 15 14 14 14 13 12 23 33

 Wood 7

 0 33 38 35 39 37 61 72 81

 Waste 8

 0 13 23 22 23 23 28 29 29

 Solar Thermal and 

Photovoltaic N/A 0 0 1 1 1 2 3 6

 Wind N/A 3 6 7 10 11 26 32 35

Total Renewable Energy 285 357 356 295 351 359 436 465 489

Generation for Own Use 9

 N/A N/A N/A N/A N/A N/A -204 -229 -248 

Other 10 N/A 4 5 5 6 5 10 10 10 

Total Electricity Generation 2,290 3,038 3,802 3,737 3,858 3,848 4,526 5,313 5,767

Sources: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.2a, 

and EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), Tables A8 and 

A16.

Notes: 

Data include electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell 

electricity, or electricity and heat, to the public. Through 1988, data are for generation at electric utilities only. 

Beginning in 1989, data also include generation at independent power producers and the commercial and industrial 

(end-use) sectors. 

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 

2 Distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, and waste oil. 

3 Natural gas, including a small amount of supplemental gaseous fuels. Forecast data Include electricity generation 

from fuel cells. 

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels, including 

refinery and still gas. 

5 Pumped storage facility production minus energy used for pumping. Data for 1980 included in conventional 

hydroelectric power. 

6 Hydroelectric data through 1988 are for generation at electric utilities and industrial plants only; beginning in 1989, 

data also include generation at independent power producers and commercial plants. 

7 Wood, black liquor, and other wood waste. 

8 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. 

9

 Includes nonutility and end-use sector generation for own use. 

10 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies. 

177
Table 7.2 – Net Generation at Electricity-Only Plants

(Billion Kilowatthours)

1980 1990 2000 2001 2002 2003 2010 2020 2025

 

 Coal 1 1,162 1,560 1,911 1,852 1,881 1,916 2,169 2,440 2,836

 Petroleum 2

 246 118 98 113 83 106 112 124 128

 Natural Gas 3

 346 265 399 427 457 406 634 1,038 1,048

 Other Gases 4

 N/A 0 0 0 0 0 N/A N/A N/A

Total Fossil Energy 1,754 1,942 2,408 2,392 2,422 2,428 2,915 3,602 4,012

Nuclear 251 577 754 769 780 764 813 830 830

Hydroelectric Pumped Storage5

 N/A -4 -6 -9 -9 -9 -9 -9 -9

 Conventional Hydroelectric 6

 276 290 271 214 260 269 300 301 301

 Geothermal 5.1 15 14 14 14 13 12 23 33

 Wood 7

 0.3 6 7 7 7 7 28 32 37

 Waste 8

 0 10 18 17 17 17 26 26 26

 Solar Thermal and 

Photovoltaic N/A 0 0 1 1 1 1 2 2

 Wind N/A 3 6 7 10 11 26 32 35

Total Renewable Energy 282 324 316 259 311 318 393 416 434

Other 9

 N/A 0 0 0 1 0 N/A N/A N/A

Total Electricity Generation 2,286 2,840 3,473 3,411 3,505 3,501 4,112 4,839 5,267 

Sources: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 

8.2c, and EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), Tables A8 

and A16.

Notes: 

Data are for electricity-only plants in the electric power sector whose primary business is to sell electricity to the 

public. Through 1988, data are for generation at electric utilities only. Beginning in 1989, data also include 

generation at independent power producers. 

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 2 Distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, and waste oil. 3 Natural gas, including a small amount of supplemental gaseous fuels. Forecast data Include electricity generation 

from fuel cells. 

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels, including 

refinery and still gas. 

5 Pumped storage facility production minus energy used for pumping. Data for 1980 included in conventional 

hydroelectric power. 

6 Hydroelectric data through 1988 are for generation at electric utilities and industrial plants only; beginning in 1989, 

data also include generation at independent power producers and commercial plants. 7 Wood, black liquor, and other wood waste. 

8 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. 

9

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies. 

 

178
Table 7.3 – Electricity Generation at Combined-Heat-and-Power Plants 

(Billion Kilowatthours)

1980 1990 2000 2001 2002 2003 2010 2020 2025

 

 Coal 1 N/A 33 55 51 51 53 54 54 54

 Petroleum 2

 N/A 8 13 11 11 12 15 19 20

 Natural Gas 3

 N/A 105 197 208 230 219 288 337 355

 Other Gases 4

 N/A 10 14 9 11 11 4 5 5

Total Fossil Energy N/A 157 279 279 303 295 361 415 434

Nuclear N/A N/A N/A N/A N/A N/A N/A N/A N/A

Hydroelectric Pumped Storage5

 N/A N/A N/A N/A N/A N/A N/A N/A N/A

 Conventional Hydroelectric 6

 N/A 3 4 3 4 6 6 6 6

 Geothermal N/A N/A N/A N/A N/A N/A 0 0 0

 Wood 7

 N/A 27 30 29 31 30 34 40 43

 Waste 8

 N/A 1 3 2 3 3 2 2 2

 Solar Thermal and Photovoltaic N/A N/A N/A N/A N/A N/A 1 2 4

 Wind N/A N/A N/A N/A N/A N/A N/A N/A N/A

Total Renewable Energy N/A 32 38 35 39 39 43 50 55

Other 9

 N/A 4 5 5 4 5 10 10 10

Total Electricity Generation N/A 192 321 319 346 339 413 475 500 

Sources: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), 

Table 8.2c, and EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), 

Tables A8 and A16.

Notes: Includes combined-heat-and-power (CHP) plants whose primary business is to sell electricity and 

heat to the public. 

For 1989-2002, does not include electric utility CHP plants—these are included in "Net Generation at 

Electricity-Only Plants " in Table 7.2. Also includes commercial and industrial CHP and a small number of 

commercial and industrial (end-use sectors) electricity-only plants. 1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 2 Distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, and waste oil. 3 Natural gas, including a small amount of supplemental gaseous fuels. Forecast data Include electricity 

generation from fuel cells. 

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels, 

including refinery and still gas. 

5 Pumped storage facility production minus energy used for pumping. Data for 1980 included in conventional 

hydroelectric power. 

6 Hydroelectric data through 1988 are for generation at electric utilities and industrial plants only; beginning in 

1989, data also include generation at independent power producers and commercial plants. 7 Wood, black liquor, and other wood waste. 

8 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. 

9

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies. 

179
Table 7.4 – Generation and Transmission/Distribution Losses

(Billion kWh) 

1980 1990 2000 2001 2002 2003 2010 2020 2025

 

Net Generation 

Delivered 2,290 3,038 3,802 3,737 3,858 3,848 4,322 5,085 5,522

Generation Losses 1

 4,859 6,305 7,793 7,578 7,767 7,769 8,506 9,507 10,137

Transmission and 

Distribution Losses 2 N/A 224 238 224 247 195 260 289 311

Sources: Calculated from EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 

2004), Tables 8.1, 8.2a and 8.4a, and EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., 

February 2005), Tables A2 and A8.

Notes:

1

 Generation Losses for all years are calculated by calculating a Gross Generation value in billion kWh by 

multiplying the energy input in trillion Btu by (1000/3412) and subtracting the Net Generation in billion kWh from 

the Gross Generation estimate. 

2

 Transmission and Distribution Losses = Electricity Needed to be Transmitted - Electricity Sales, where 

Electricity Needed to be Transmitted = Total Generation from Electric Generators + Cogenerators + Net Imports - 

Generation for Own Use. Represents energy losses that occur between the point of generation and delivery to the 

customer, and data collection frame differences and nonsampling error. 

180
Table 7.5 – Electricity Trade 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2010 2020 2025

 

Interregional Electricity Trade 

Gross Domestic Firm Power Trade N/A N/A N/A 143 139 137 106 51 38

Gross Domestic Economy Trade N/A N/A N/A 182 210 199 207 133 102

Gross Domestic Trade N/A N/A N/A 325 349 335 312 184 140

 

International Electricity Trade Firm Power Imports from Mexico and 

Canada N/A N/A N/A 12 10 11 2 1 0

Economy Imports from Mexico and 

Canada N/A N/A N/A 26 27 18 29 31 25

Gross Imports from Mexico and Canada 25 18 49 39 36 31 31 32 25

 

Firm Power Exports to Mexico and Canada N/A N/A N/A 7 6 6 1 0 0

Economy Exports to Mexico and Canada N/A N/A N/A 10 9 20 21 16 14

Gross Exports to Canada and Mexico 4 16 15 16 14 24 22 16 14

 

Sources: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 

8.1, and EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), Table 

A10.

Notes:

All data are from EIA AEO except Gross Imports and Exports for 1980-2003. 

181
182
Table 8.1 – Electricity Sales

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2010 2020 2025

Electricity Sales by Sector1 Residential 717 924 1,192 1,203 1,267 1,280 1,471 1,696 1,810  Commercial 488 751 1,055 1,089 1,116 1,119 1,466 1,854 2,088  Industrial 815 946 1,064 964 972 991 1,107 1,229 1,286  Transportation/Other 2 74 92 109 114 107 109 26 32 35  Total Sales 2,094 2,713 3,421 3,370 3,463 3,500 4,070 4,811 5,220  Direct Use 3 N/A 114 183 184 178 175 204 229 248 Total 2,094 2,827 3,605 3,554 3,641 3,675 4,274 5,040 5,467Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), Table A8; EIA, Annual 

Energy Review 2003, DOE/EIA-0384(2002) (Washington, D.C., September 2004), Table 8.9. 

Notes: 

1 Electricity retail sales to ultimate customers reported by electric utilities and other energy service providers.

2 Other includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and 

interdepartmental sales through 2002. Transportation sector sales reported starting in 2010.

3 Commercial and industrial facility use of onsite net electricity generation; and electricity sales among adjacent or colocated

facilities for which revenue information is not available. 

183
Table 8.2 – Demand-Side Management

1980 1990 2000 2001 

Load Management Peak Load Reductions (MW)1 NA 7,911 10,027 11,928 

Energy Efficiency Peak Load Reductions (MW)2 NA 5,793 12,873 13,027 

Total Peak Load Reductions (MW) NA 13,704 22,901 24,955 Energy Savings (Million kWh) NA 20,458 53,701 54,762 Costs (Million 2000 $)3 NA 1,506 1,620 1,649 

Sources: Sources: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.13; 

Annual 2003, DOE/EIA-0348(2003) (Washington, D.C., December 2004), table 9.1, 9.4 and 9.7 Notes: The actual reduction in peak load reflects the change in demand for electricity that results from a utility demand-side manageme

at the time that the utility experiences its actual peak load as opposed to the potential installed peak load reduction capability. D

and potential peak reduction result from changes in weather, economic activity, and other variable conditions. 

1 Load management includes programs such as direct load control and interruptible load control, and beginning in 1997, "other t

management programs. "Other types" are programs that limit or shift peak loads from on-peak to off-peak time periods, such as heating storage systems. 

2 Energy efficiency refers to programs that are aimed at reducing the energy used by specific end-use devices and systems, typ

services provided. From 1989 to 1996, energy efficiency includes "other types" of demand-side management programs. Beginn

programs are included under load management. 

3 Historical data converted to 2000 dollars using EIA Annual Energy Review 2003, Appendix D. 

184
Table 8.3 - Electricity Sales, Revenue, and Consumption by Census Division and Stat

Census Division 

and State Sales (MWh) 

Revenue 

(million $)

Average 

Revenue 

(¢/kWh)

Electricity 

Consumption 

(kWh/person) 

Census Division 

and State Sales (MWh)

Revenue 

(million $

New England 122,641,448 12,816 10.4 8,636 East South Central 312,064,000 17,3

Connecticut 31,783,319 3,231 10.2 9,115 Alabama 83,844,220 4,9Maine 11,971,837 1,172 9.8 9,144 Kentucky 85,219,631 3,7Massachusetts 54,728,455 5,820 10.6 8,524 Mississippi 45,543,881 2,9New Hampshire 11,005,912 1,188 10.8 8,540 Tennessee 97,455,808 5,6Rhode Island 7,799,496 816 10.5 7,248 West South Central 93,991,704 35,1Vermont 5,352,429 588 11.0 8,642 Arkansas 43,108,259 2,3Middle Atlantic 361,813,094 36,437 10.1 8,995 Louisiana 77,769,322 5,3New Jersey 76,589,333 7,245 9.5 8,862 Oklahoma 50,428,168 3,2New York 144,222,104 17,936 12.4 7,507 Texas 322,685,955 24,2Pennsylvania 141,001,657 11,256 8.0 11,398 Mountain 231,061,000 15,5

East North Central 563,972,401 36,894 6.5 12,302 Arizona 64,079,560 4,7

Illinois 135,973,629 9,359 6.9 10,750 Colorado 46,494,645 3,1Indiana 100,467,779 5,393 5.4 16,206 Idaho 21,218,685 1,1Michigan 108,877,193 7,461 6.9 10,799 Montana 12,691,252 7Ohio 151,412,306 10,213 6.7 13,238 Nevada 30,131,660 2,4Wisconsin 67,241,494 4,468 6.6 12,283 New Mexico 19,330,491 1,3West North Central 260,667,000 15,720 6.0 15,647 Utah 23,860,350 1,2Iowa 41,207,284 2,519 6.1 14,007 Wyoming 13,253,836 6Kansas 36,735,390 2,333 6.3 13,482 Pacific Contiguous 362,037,959 35,1Minnesota 63,087,339 3,791 6.0 21,500 California 238,709,728 27,7Missouri 74,239,888 4,470 6.0 12,981 Oregon 45,194,730 2,7Nebraska 25,856,566 1,458 5.6 14,882 Washington 78,133,501 4,5North Dakota 10,461,108 572 5.5 16,516

Pacific Noncontiguous 15,954,518 2,0

South Dakota 9,079,990 577 6.4 11,871 Alaska 5,563,682 5

185
South Atlantic 763,991,000 51,697 6.8 14,067 Hawaii 10,390,836 1,5

Delaware 12,599,590 877 7.0 15,400 U.S. Total 3,488,191,978 258,7

District of Columbia 10,879,622 808 7.4 19,511

Florida 217,378,622 16,774 7.7 12,788Georgia 123,676,657 7,816 6.3 14,254Maryland 71,258,583 4,594 6.4 12,927North Carolina 121,335,121 8,329 6.9 14,408South Carolina 77,054,098 4,684 6.1 18,573Virginia 101,509,984 6,364 6.3 13,782West Virginia 28,296,993 1,450 5.1 15,621Sources: EIA, Electric Sales and Revenue 2003 Spreadsheets, Data Tables, http://www.eia.doe.gov/cneaf/electricity/esr/esr_t

1d, and U.S. Census Bureau, Annual Estimates of the Population for the United States and States, and for Puerto Rico: April 1, 

(NST-EST2004-01) - State Population Estimates: 2003, http://www.census.gov/popest/national/files/NST_EST2004_ALLDATA.

Notes: 

Revenue in 2003 dollars. Includes bundled and unbundled consumers 

186
Table 9.1 – Price of Fuels Delivered to Electric Generators

(2003 Dollars per Million Btu) 1

1980 1992 2000 2001 2002 2003 2010 20

Distillate Fuel NA NA N

A NA NA N

A 5.36 6.

Residual Fuel 2 NA 3.08 4.42 3.81 3.40 4.45 4.19 4.

Natural Gas 3 NA 2.85 4.55 4.63 3.62 5.37 4.27 5.

Steam Coal 4 NA 1.73 1.27 1.27 1.28 1.28 1.25 1.

Fossil Fuel Average 5 NA 1.94 1.83 1.79 1.54 2.19 2.06 2.

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), Table A3, and EIA, Electric Power An

DOE/EIA-0348(2003) (Washington, D.C., December 2004), Table 4.5.

Notes:Includes electricity-only and combined heat and power plants whose primary business is to sell electricity, or electricity and heat, to the public

Data are for steam-electric plants with a generator nameplate capacity of 50 or more megawatts. Beginning in 2002, data from the Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report" for independent power produce

combined heat and power producers are included in this data dissemination. Prior to 2002, these data were not collected; the data for 2001 a

years include only data collected from electric utilities via the FERC Form 423. 

1 Historical Data converted to 2003$/MMBtu using EIA Annual Energy Review 2003 Appendix D. 2 1990-2003 data are for distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker 

fuel, kerosene, petroleum coke (converted to liquid petroleum), and waste oil. 

3 Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. 4 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 5 Weighted average price. 

187
Table 9.2 – Electricity Retail Sales

(Billion Kilowatthours)

1980 1990 2000 2001 2002 2003 2010 2020 

Retail Sales1Residential 717 924 1,192 1,203 1,267 1,280 1,471 1,696 Commercial 488 751 1,055 1,089 1,116 1,119 1,466 1,854 Industrial 815 946 1,064 964 972 991 1,107 1,229 Transportation / Other3 74 92 109 114 107 109 26 32 Total 2,094 2,713 3,421 3,370 3,463 3,500 4,070 4,811 Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005), (Washington, D.C., February 2005), Table A8 and EIA, Annual Energy R

2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Table 8.9.

Notes:

1 Electricity retail sales to ultimate customers by electric utilities and, beginning in 1996, other energy service providers. 2 Other includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sale

through 2003. Transportation sector sales reported starting in 2010.

188
Table 9.3 – Prices of Electricity Sold

(2003 cents per Kilowatthour) 1

1980 1990 2000 2001 2002 2003 2010 2020 20

Price by End-Use Sector2Residential 10.6 10.1 8.7 8.9 8.6 8.7 7.8 8.2 Commercial 10.8 9.5 7.9 8.2 8.0 8.1 6.8 7.5 Industrial 7.2 6.1 4.9 5.2 5.0 5.0 4.7 5.3 Transportation / Other3 9.4 8.3 6.9 7.3 6.8 7.0 6.4 6.8 End-Use Sector Average 9.2 8.5 7.2 7.6 7.3 7.4 6.6 7.2 Price by Service Category2Generation N/A N/A N/A N/A 4.7 4.8 4.1 4.7 Transmission N/A N/A N/A N/A 0.6 0.5 0.6 0.7 Distribution N/A N/A N/A N/A 2.1 2.1 2.0 1.8 Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005), (Washington, D.C., February 2005), Table A8 and EIA, Annual 

Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table 8.10.

Notes:For 1980, data are for selected Class A utilities whose electric operating revenues were $100 million or more during the previous year. 

For 1990, data are for a census of electric utilities. For 2000 onward, data also include energy service providers selling to retail customers. 1 Historical Data real prices expressed in chained (2003) dollars, calculated by using gross domestic product implicit price deflators 

using EIA Annual Energy Review 2003 Appendix D. 

2 Prices represent average revenue per kilowatthour. 3 Public street and highway lighting, other sales to public authorities, sales to railroads and railways and interdepartmental sales. 

189
Table 9.4 – Revenue from Electric Utility Retail Sales by Sector

(Millions of 2003 Dollars) 

1980 1990 2000 2001 2002 2003 2010 2020 2025

Residential 71,750 88,706 98,258 101,263 103,130 105,464 115,251 139,584 149,710Commercial 49,792 67,592 78,404 84,409 84,388 86,070 99,691 139,850 159,617Industrial 55,425 54,935 49,381 47,440 45,595 46,396 52,282 64,843 69,121Transportation/Other 1 6,562 7,212 7,183 7,815 6,932 7,202 1,682 2,170 2,391All Sectors 2 182,217 218,361 232,998 240,939 240,299 244,998 268,906 346,448 380,838Sources: Calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005), (Washington, D.C., February 2005), Table A8; 

EIA, Annual Energy Review 2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Tables 8.9 and 8.10.

Notes:

1 Other includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and 

interdepartmental sales through 2003. Transportation sector revenue reported starting in 2010. 2 For 1980, data are for selected Class A utilities whose electric operating revenues were $100 million or more during the previous 

year. For 1990, data are for a census of electric utilities. For 2000 onward, data also include energy service providers selling to retail 

customers 

190
Table 9.5 – Revenue from Sales to Ultimate Consumers by Sector, Census Division, a

(Millions of 2003 Dollars)Census Division/ State 

Residential Commer- cial Industrial Other1 All Sectors 2 Census Division/ State Residen- tial Commer- cial Ind

New England 5,382 5,395 2,012 27 12,816 East South Central 7,420 5,111 

 Connecticut 1,492 1,292 433 15 3,231 Alabama 2,175 1,399  Maine 522 409 241 0 1,172 Kentucky 1,435 963  Massachusetts 2,253 2,684 871 12 5,820 Mississippi 1,343 913  New Hampshire 509 445 234 0 1,188 Tennessee 2,467 1,836  Rhode Island 348 352 116 0 816 West South Central 15,989 10,877  Vermont 258 212 117 0 588 Arkansas 1,130 585 Middle Atlantic 14,424 16,431 5,243 338 36,437 Louisiana 2,241 1,628  New Jersey 2,921 3,335 976 13 7,245 Oklahoma 1,507 1,083  New York 6,743 9,372 1,552 269 17,936 Texas 11,111 7,581  Pennsylvania 4,760 3,724 2,715 57 11,256 Mountain 6,409 5,700 East North Central 14,541 12,483 9,839 30 36,894 Arizona 2,316 1,803  Illinois 3,616 3,690 2,025 28 9,359 Colorado 1,280 1,298  Indiana 2,162 1,374 1,855 1 5,393 Idaho 443 304  Michigan 2,813 2,672 1,976 0 7,461 Montana 311 292  Ohio 4,097 3,349 2,766 0 10,213 Nevada 932 718  Wisconsin 1,853 1,397 1,217 0 4,468 New Mexico 471 593 West North Central 6,958 5,420 3,342 0 15,720 Utah 494 504  Iowa 1,094 726 699 0 2,519 Wyoming 161 189  Kansas 971 882 479 0 2,333 Pacific Contiguous 12,949 15,856  Minnesota 1,579 1,257 955 0 3,791 California 9,686 13,167  Missouri 2,186 1,618 667 0 4,470 Oregon 1,252 988  Nebraska 608 499 352 0 1,458 Washington 2,010 1,701 

191
 North Dakota 241 214 117 0 572

Pacific Noncontiguous 745 788 

 South Dakota 280 224 73 0 577 Alaska 238 259 South Atlantic 25,963 17,711 7,949 74 51,697 Hawaii 507 528  Delaware 360 284 233 0 877 U.S. Total 110,779 95,772  District of Columbia 144 627 14 22 808

 Florida 9,636 6,083 1,048 7 16,774 Georgia 3,711 2,699 1,397 9 7,816 Maryland 2,060 1,178 1,329 27 4,594 North Carolina 4,106 2,770 1,453 0 8,329 South Carolina 2,117 1,316 1,251 0 4,684 Virginia 3,174 2,365 815 9 6,364 West Virginia 654 389 408 0 1,450Source: EIA, Electric Sales and 

Revenue 

200

3 Spreadsheets, Data 

Tables, http://w

w

w.eia.doe.gov/cneaf/electricity/esr/esr_tabs.html, Table 

Notes:1 Includes sales for public street and highway lighting, to public authorities, railroads and railways, and interdepartmental sales2 Includes bundled and unbundled Consumers

192
Table 9.6 – Production, Operation, and Maintenance Expenses for Major U.S. 

Investor-Owned and Publicly Owned Utilities (Million of Nominal Dollars)

Investor-Owned Utilities Publicly 

1990 1995 2000 2002 2003 1990 1995 

Production Expenses  Cost of Fuel 32,635 29,122 32,555 24,132 26,476 5,276 5,664  Purchased Power 20,341 29,981 61,969 58,828 62,173 10,542 11,988  Other Production Expenses 9,526 9,880 12,828 7,688 7,532 155 212  Total Production Expenses2 62,502 68,983 107,352 90,649 96,181 15,973 17,863 Operation and Maintenance Expenses  Transmission Expenses 1,130 1,425 2,699 3,494 3,585 604 663  Distribution Expenses 2,444 2,561 3,115 3,113 3,185 950 630  Customer Accounts Expenses 3,247 3,613 4,246 4,165 4,180 375 448  Customer Service and Information Expenses 1,181 1,922 1,839 1,821 1,893 75 120  Sales Expenses 212 348 403 261 234 29 30  Administrative and General Expenses 10,371 13,028 13,009 12,872 13,466 1,619 2,127  Total Electric Operation and Maintenance Expenses 18,585 22,897 25,311 25,726 26,543 3,653 4,018 Source: EIA, Electric Power Annual 2003, DOE/EIA-0348(2003) (Washington, D.C., December 2004), Tables 8.1, 8.3 and 8.4; and EIA, Elec

0348(2001) (Washington, D.C., December 2002), Table 8.1; EIA, Financial Statistics of Major US Publicly Owned Electric Utilities 1994, DOE/D.C., December 1995), Table 8 and Table 17; EIA, Financial Statistics of Major US Publicly Owned Electric Utilities 1999, DOE/EIA-0437(99)/

2000), Table 10 & Table 21; EIA, Financial Statistics of Major US Publicly Owned Electric Utilities 2000, DOE/EIA-0437(00)/2 (Washington, D

Table 21.; EIA, Public Electric Utility Database (Form EIA-412) 2002 and 2003. Notes:

1 Publicly Owned Utilities include generator and nongenerator electric utilities.2 Totals may not equal sum of components because of independent rounding. 

193
Table 9.6a – Operation and Maintenance Expenses for Major 

U.S. Investor-Owned Electric Utilities

(Million of Nominal Dollars, unless otherwise indicated)

1990 1995 2000 2002 2003

Utility Operating 

Expenses 142,471 165,321 210,324 188,745 197,459

Electric Utility 127,901 150,599 191,329 171,291 175,473

Operation 81,086 91,881 132,662 116,374 122,723

 Production 62,501 68,983 107,352 90,649 96,181

 Cost of Fuel 32,635 29,122 32,555 24,132 26,476

 Purchased Power 20,341 29,981 61,969 58,828 62,173

 Other 9,526 9,880 12,828 7,688 7,532

 Transmission 1,130 1,425 2,699 3,494 3,585

 Distribution 2,444 2,561 3,115 3,113 3,185

 Customer Accounts 3,247 3,613 4,246 4,165 4,180

 Customer Service 1,181 1,922 1,839 1,821 1,893

 Sales 212 348 403 261 234

 Administrative and 

General 10,371 13,028 13,009 12,872 13,466

Maintenance 11,779 11,767 12,185 10,843 11,141

Depreciation 14,889 19,885 22,761 17,319 16,962

Taxes and Other 20,146 27,065 23,721 26,755 24,648

Other Utility 14,571 14,722 18,995 17,454 21,986

Operation (Mills per 

Kilowatthour) 1 

 Nuclear 10.04 9.43 8.41 8.54 8.86

 Fossil Steam 2.21 2.38 2.31 2.54 2.50

 Hydroelectric & Pumped 

Storage 3.35 3.69 4.74 5.07 4.50

 Gas Turbine and Small 

Scale 2

 8.76 3.57 4.57 2.72 2.76

Maintenance (Mills per 

Kilowatthour) 1

 Nuclear 5.68 5.21 4.93 5.04 5.23

 Fossil Steam 2.97 2.65 2.45 2.68 2.73

 Hydroelectric & Pumped 

Storage 2.58 2.19 2.99 3.58 3.01

 Gas Turbine and Small 

Scale 2

 12.23 4.28 3.50 2.38 2.26

Source: EIA, Electric Power Annual 2003, DOE/EIA-0348(2003) (Washington, D.C., December 2004), Tables 

8.1 and 8.2, and EIA, Electric Power Annual 2001, Tables 8.1 and 8.2.

Notes:

1 Operation and maintenance expenses are averages, weighed by net generation. 2 Includes gas turbine, internal combustion, photovoltaic, and wind plants.

194
Table 9.6b – Operation and Maintenance Expenses for Major 

U.S. Publicly Owned Generator and Nongenerator Electric Utilities 

(Million of Nominal Dollars, except employees) 

1990 1995 2000 2002 2003

 

Production Expenses 

 Steam Power Generation 3,742 3,895 5,420 6,558 7,539

 Nuclear Power Generation 1,133 1,277 1,347 1,646 1,739

 Hydraulic Power Generation 205 261 332 746 785

 Other Power Generation 196 231 603 1,144 1,100

 Purchased Power 10,542 11,988 16,481 24,446 26,078

 Other Production Expenses 155 212 225 1,647 1,285

 Total Production Expenses1

 15,973 17,863 24,398 36,188 38,526

Operation and Maintenance Expenses 

 Transmission Expenses 604 663 845 951 977

 Distribution Expenses 950 630 854 1,000 1,044

 Customer Accounts Expenses 375 448 662 700 754

 Customer Service and Information Expenses 75 120 233 354 311

 Sales Expenses 29 30 82 84 95

 Administrative and General Expenses 1,619 2,127 2,097 2,594 2,742

 Total Electric Operation and Maintenance Expenses 3,653 4,018 4,772 5,683 5,923

Total Production and Operation and Maintenance Expenses 19,626 22,651 30,100 44,813 47,165

Fuel Expenses in Operation 

 Steam Power Generation 2,395 2,163 4,150 4,818 5,624

 Nuclear Power Generation 242 222 316 433 398

 Other Power Generation 113 101 373 754 771

 

Total Electric Department Employees2 N/A 73,172 71,353 93,520 92,752

 

Source: EIA, Financial Statistics of Major US Publicly Owned Electric Utilities 1994, DOE/EIA-0437(94)/2 (Washington, D.C., 

December 1995), Table 8 and Table 17; EIA, Financial Statistics of Major U.S. Publicly Owned Electric Utilities 1999, DOE/EIA0437(99)/2 (Washington, D.C., November 2000), Table 10 & Table 21; EIA, Financial Statistics of Major US Publicly Owned 

Electric Utilities 2000, DOE/EIA-0437(00)/2 (Washington, D.C., November 2001), Table 10 & Table 21; EIA, Public Electric Utility 

Database (Form EIA-412) 2002 and 2003; EIA, Electric Power Annual 2003, DOE/EIA-0348(2003) (Washington, D.C., December 

2004), Tables 8.3 and 8.4

Notes:

1

 Totals may not equal sum of components because of independent rounding.

2

 Number of employees were not submitted by some publicly owned electric utilities because the number of electric utility 

employees could not be separated from the other municipal employees or the electric utility outsourced much of the work. 

195
Table 9.7 – Environmental Compliance Equipment Costs

(Nominal Dollars) 

1990 1995 2000 2001 2002 2003 2010 2020 2025

Average Flue Gas Desulfurization Costs 

at Utilities 

Average Operation & Maintenance Costs 

(mills/kWh) 1.35 1.16 0.96 1.27 1.11 1.23 N/A N/A N/A

Average Installed Costs ($/kW) 118 126 124 131 124 124 N/A N/A N/A

Source: EIA, Electric Power Annual 2001, DOE/EIA-0348 (01) (March 2003), Table 5.3, Electric Power Annual 2003, Table 5.3.

Notes:

Includes plants under the Clean Air Act that were monitored by the Environmental Protection Agency even if sold to an 

unregulated entity.

These data are for plants with a fossil-fueled steam-electric capacity of 100 megawatts or more.

 

196
Table 10.1 – Consumer Price Estimates for Energy Purchases 

(2003 Dollars, per Million Btu)1

1970 1980 1990 2000 2002 2003 2010 

Coal 1.38 2.70 1.84 1.27 1.29 1.30 1.27 Natural Gas 2.14 5.29 4.72 5.68 5.15 6.86 5.52  Distillate Fuel 4.21 12.40 9.44 9.90 8.71 9.90 9.53  Jet Fuel 2.65 11.77 6.96 6.60 6.05 6.46 6.25  Liquified Petroleum Gases 5.30 10.44 8.27 10.19 9.52 13.04 10.99  Motor Gasoline 10.35 18.21 11.18 12.01 11.32 12.93 12.31  Residual Fuel 1.53 7.18 3.87 4.74 3.93 4.66 3.99  Other 2 5.01 12.99 7.11 6.98 N/A N/A N/A 

Petroleum Total 6.25 13.69 9.16 9.94 9.09 10.51 9.91 

Nuclear Fuel 0.65 0.80 0.82 0.45 N/A N/A N/A Wood and Waste 4.69 4.18 2.08 1.90 N/A N/A N/A Primary Energy Total 3 3.92 8.46 5.50 5.78 7.78 9.01 8.61 

Electric Utility Fuel 1.16 3.24 1.79 1.43 N/A N/A N/A Electricity Purchased by End Users 18.09 25.81 23.69 20.04 21.60 21.74 19.36 Total Energy 3 5.99 12.75 10.11 9.85 10.26 11.50 10.56 

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005), (Washington, D.C., February 2005), Table A3 and EIA, A

2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Table 3.3.

Notes:

1 Historical Data converted to 2003$/MMBtu using EIA Annual Energy Review 2003 Appendix D. 2 Consumption-weighted average price for asphalt and road oil, aviation gasoline, kerosene, lubricants, petrochemical feedst

special naphthas, waxes, and miscellaneous petroleum products. 3 The "Primary Energy Total" and "Total Energy" prices include consumption-weighted average prices for coal coke imports a

are not shown in the other columns. 

197
Table 10.2 – Economy-Wide Indicators

(Billions of 2000 Chain Weighted Dollars, unless otherwise noted)

1980 1990 2000 2001 2002 2003 201

GDP Chain Type Price Index (2000 = 1.000) 0.541 0.816 1.000 1.024 1.041 1.060 1.21

Real Gross Domestic Product 5,162 7,113 9,817 9,891 10,075 10,381 13,08

 Real Consumption 3,374 4,770 6,739 6,910 7,123 7,356 9,03 Real Investment 645 895 1,736 1,598 1,561 1,629 2,32 Real Government Spending 1,115 1,530 1,722 1,780 1,858 1,909 2,13

 Real Exports 324 553 1,096 1,037 1,012 1,032 1,91 Real Imports 311 607 1,476 1,436 1,484 1,550 2,28Real Disposable Personal Income 3,858 5,324 7,194 7,333 7,560 7734 9,59

Consumer Price Index (2002 = 1.000) 0.824 1.307 1.722 1.771 1.799 1.840 2.1

Unemployment Rate (percent) 7.1 5.6 4.0 4.7 5.8 6.0 5.5Housing Starts (millions) 1.3 1.2 1.6 1.6 1.7 1.8 1.8Gross Output 

Total Industrial 5,067 5,105 6,16 Non-Manufacturing 1,240 1,254 1,32 Manufacturing 3,826 3,851 4,83 Energy-Intensive Manufacturing 1,057 1,048 1,21 Non-Energy-Intensive Manufacturing Population (all ages, millions) 226.5 248.8 281.4 285.1 288.0 290.8 310Employment Non-Agriculture (millions) 95.9 115.6 134.4 134.6 134.2 135.5 140

Employment Manufacturing (millions) 20.4 19.2 17.5 16.5 15.3 14.6 14Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383(2005) (Washington, D.C., February 2005), Table A19, EIA, Annua

DOE/EIA-0384(2002) (Washington, D.C., October 2003), Table D1, Bureau Of Economic Analysis, National Income and Produ(NIPA), Tables 1.1.4, 1.1.6, 2.1, and 6.4 B-D, http://www.bea.doc.gov/bea/dn/nipaweb/NIPATableIndex.asp, Department of Lab

Statistics, Current Population Survey, Current Population Survey, Household Data Annual Averages, http://www.bls.gov/cps/cp

Association of Home Builders, http://www.nahb.org/generic.aspx?sectionID=130&genericContentID=554.

198
Table 10.3 – Composite Statements of Income for Major U.S. Publicly Owned Gene

and Investor-Owned Electric Utilities, 2003 (Million 2003 Dollars) 

Publicly Owned Generator Inv

Electric Utilities 1 Ele

Operating Revenue - Electric 33,906 Operating Expenses - Electric 29,637 Operation Including Fuel 22,642  Production 17,948  Transmission 872  Distribution 696  Customer Accounts 582  Customer Service 280  Sales 84  Administrative and General 2,180 Maintenance 2,086 Depreciation and Amortization 3,844 Taxes and Tax Equivalents 1,066 Net Electric Operating Income 4,268 Source: EIA, Electric Power Annual 2003, DOE/EIA-0348(2003), (Washington, D.C., December 2004), Tables 8.1 and 8.3

Note:

1 The data represent those utilities meeting a threshold of 150 million kilowatthours of customer sales or resale for the two p

199
200
Table 11.1 – Emissions from Electricity Generators, 2003 

 (Thousand short tons of gas)

1990 2000 2001 2002 2003 2010 2020 

Coal Fired  Carbon Dioxide 1,672,757 2,083,038 2,016,017 2,059,779 2,099,132 2,358,682 2,614,183 2,9

 Sulfur Dioxide 15,220 10,623 10,004 9,732 N/A N/A N/A  Nitrogen Oxide 5,642 4,563 4,208 4,094 N/A N/A N/A  Methane 11 13 13 13 N/A N/A N/A  Nitrous Oxide 25 31 31 31 32 N/A N/A Petroleum Fired 

 Carbon Dioxide 108,467 98,106 108,798 78,374 106,373 106,147 117,840 1 Sulfur Dioxide 639 482 529 343 N/A N/A N/A  Nitrogen Oxide 221 166 170 130 N/A N/A N/A  Methane 1 1 1 0 0 N/A N/A  Nitrous Oxide 1 1 1 1 1 N/A N/A Gas Fired  Carbon Dioxide 188,275 298,065 305,230 315,812 303,466 399,152 559,935 5 Sulfur Dioxide 1 232 262 8 N/A N/A N/A  Nitrogen Oxide 565 422 359 270 N/A N/A N/A  Methane 0 1 1 1 0 N/A N/A  Nitrous Oxide 0 1 1 1 0 N/A N/A Other 1 Carbon Dioxide N/A N/A N/A N/A N/A N/A N/A  Sulfur Dioxide 2 49 59 55 210 N/A N/A N/A  Nitrogen Oxide 2 235 180 180 206 N/A N/A N/A  Methane N/A N/A N/A N/A N/A N/A N/A  Nitrous Oxide 3 1 1 0 1 1 N/A N/A Total  Carbon Dioxide 1,969,610 2,479,319 2,430,156 2,453,966 2,512,498 2,886,482 3,315,362 3,6

 Sulfur Dioxide 15,909 11,396 10,850 10,293 N/A 9,290 8,950 

201
 Nitrogen Oxide 6,663 5,330 4,917 4,699 N/A 3,989 4,175 

 Mercury N/A N/A N/A 50,081 49,699 54,076 55,452  Methane 12 14 14 14 14 N/A N/A  Nitrous Oxide 26 33 33 33 34 N/A N/A  Sulfur Hexafluoride 4 2 1 1 1 1 N/A N/A 

Sources: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Tables A8 and A18, EI

Emissions of Greenhouse Gases in the United States 2003, DOE/EIA-0573(2003) (Washington, D.C., December 2004) Tables 25, 29, and EPA, National Emission Inventory - Air Pollutant Emission Trends, “Average Annual Emissions, All Criteria PollutantAugust 2003, http://www.epa.gov/ttn/chief/trends/index.html.Notes:Emissions from electric-power sector only. 

1 Emissions total less than 500 tons. 2 Emissions from plants fired by other fuels; includes internal combustion generators. 3 Emissions from wood-burning plants. 4 Sulfur hexafluoride (SF6) is a colorless, odorless, nontoxic, and nonflammable gas used as an insulator in electric T&D equipm

SF6 has a 100-year global warming potential that is 22,200 times that of carbon dioxide and has an atmospheric lifetime of 3,20

years. 

202
Table 11.2 – Installed Nameplate Capacity of Utility Steam-Electric Generators 

With Environmental Equipment (Megawatts) 

1990 2000 2001 2002

Coal Fired  Particulate Collectors 315,681 321,636 329,187 329,459 Cooling Towers 134,199 146,093 154,747 154,750 Scrubbers 69,057 89,675 97,804 98,363 Total1 317,522 328,741 329,187 329,459

Petroleum and Gas Fired  Particulate Collectors 33,639 31,090 31,575 29,879 Cooling Towers 28,359 29,427 34,649 45,747 Scrubbers 65 0 184 310 Total1 59,372 57,697 61,634 71,709Total  Particulate Collectors 349,319 352,727 360,762 359,338 Cooling Towers 162,557 175,520 189,396 200,497 Scrubbers 69,122 89,675 97,988 98,673 Total1 376,894 386,438 390,821 401,168

Source: EIA, Annual Energy Review 2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Table 12.8.

Notes:

1Components are not additive because some generators are included in more than one category.

Through 2000, data are for electric utilities with fossil-fueled steam-electric capacity of 100 megawatts or greater. Beginning in 2001, data are for electric utilities and unregulated generating plants (independent power producers, commercial plants, and industrial plants) with fossil-fueled or combustible renewable steam-electric capacity of 100 

megawatts or greater.

203
Table 11.3 – EPA-Forecasted Nitrogen Oxide, Sulfur Dioxide, and Mercury Emissions 

Generators 

EPA Base Case 2000 Clear Skies Case 

2005 2010 2015 2020 2005 2010 

SO2 (Thousand Tons) 10,267 9,861 9,227 8,961 8,424 6,242 NOx (Thousand Tons) 3,896 3,951 4,017 4,066 3,647 2,186 CO2 (Thousand Tons) 2,428,503 2,632,377 2,795,022 2,960,312 2,412,371 2,599,277 2,7Mercury (Tons) 52 53 52 52 49 35 Source: Environmental Protection Agency (EPA), Clear Skies Initiative Analysis, Runs Table for EPA Modeling Applications 20http://www.epa.gov/airmarkets/epa-ipm/results2003.html, EPA Base Case for 2003 Analyses http://www.epa.gov/airmarkets/epa

ipm/EPA216a9c.zip, and 2003 Clear Skies Act Case http://www.epa.gov/airmarkets/epa-ipm/EPA216c3.zip Notes:The proposed Clear Skies legislation would create a mandatory program that would dramatically reduce power plant emissions (SO2), nitrogen oxides (NOx), and mercury by setting a national cap on each pollutant. http://www.epa.gov/air/clearskies/ 

Clear Skies would: Cut sulfur dioxide (SO2) emissions by 73 percent, from year 2000 emissions of 11 million tons to a cap of 4.5 million tons in 201

million tons in 2018. Cut emissions of nitrogen oxides (NOx) by 67 percent, from year 2000 emissions of 5 million tons to a cap of 2.1 million tons in 1.7 million tons in 2018. Cut mercury emissions by 69 percent - the first-ever national cap on mercury emissions. Emissions would be cut from 1999 emi

a cap of 26 tons in 2010 and to a cap of 15 tons in 2018. Analytical Framework of IPM • EPA uses the Integrated Planning Model (IPM) to analyze the projected impact of environmental electric power sector in the 48 contiguous states and the District of Columbia. Developed by ICF Resources Incorporated and u

and private sector clients, IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power se

provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting energy dem

environmental, transmission, dispatch, and reliability constraints. IPM can be used to evaluate the cost and emissions impacts o

to limit emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), and mercury (Hg) from the electric powe

a key analytical tool in developing the President's Clear Skies proposal. 

204
Table 11.4 – Market Price Indices for Emissions Trading in the South Coast 

Air-Quality Management District 

1996 1997 1998 1999 2000 2001 2002 20

Market Price Indices 1RECLAIM Trading Credit ($/lb) 2 Nitrogen Oxide 0.05 0.08 0.20 0.90 42.69 11.11 0.70 0 Sulfur Dioxide 0.15 0.08 0.34 0.29 1.14 6.82 4.00 2Emission Reduction Credit ($/lb/day) 3 Nitrogen Oxide 2,070 2,908 4,515 4,560 7,675 16,809 8,000 8,4 Sulfur Dioxide 1,367 1,740 1,687 1,687 3,721 7,184 7,500 70 Particulate Matter (<10 microns) 2,418 1,947 1,981 3,175 6,942 19,030 22,000 250 Reactive Organic Gas 1,075 754 744 735 1,904 1,869 1,475 11 Carbon Monoxide NA NA NA NA 1,000 7,259 7,000 70Source: Cantor Fitzgerald EBS, SCAQMD RTC/ERC MPI History, http://www.emissionstrading.com.

Notes:

1 Market Price Indices (MPIs) reflect current market conditions for a particular date. Dates used here are end of year: 11/12/96

12/21/98, 12/27/99, 12/28/00, 12/7/01, 12/19/02 and 12/19/03. 2005 and 2010 prices as of 12/30/03 for all NOx products, 7/29/

RTCs, and 07/02/03 for 2010 SOx RTCs. Prices are an average of the most recent price, lowest bid, and highest bid for RTC a

transactions executed by Cantor Fitzgerald and/or reported by the South Coast Air Quality Management District (SCAQMD) for more of RTCs or 10 lbs/day or more of ERCs. SCAQMD was chosen because it is the region with the greatest number of emiss

2 In the RECLAIM program, the RECLAIM Trading Credit (RTC) is a limited authorization to emit a RECLAIM pollutant in accord

restrictions and requirements of the RECLAIM rules. Each RTC has a denomination of one pound of RECLAIM pollutant and a t

and can be held as part of a facility’s Allocation or alternatively may be evidenced by an RTC Certificate. 3 Emissions Reduction Credits (ERCs) are reductions in emissions that have been recognized by the relevant local or state gove

as being real, permanent, surplus, and enforceable. ERCs are usually measured as a weight over time (e.g., pounds per day or 

Such rate-based ERCs can be used to satisfy emission offset requirements of new major sources and new major modifications 

sources. 

205
Table 11.5 – Origin of 2003 Allowable SO2 Emissions Levels 

Type of Allowance Allocation 

Number of

Allowances Explanation of Allowance Allocation Typ

Initial Allocation 9,191,897 Initial Allocation is the number of allowances granted to units based 

historic utilization and emissions rates (performance standards) speAct and other provisions of the Act. 

Allowance Auctions 250,000 Allowance Auctions provide allowances to the market that were set 

Allowance Reserve when the initial allowance allocation was made. 

Opt-in Allowances 99,188 Opt-in Allowances are provided to units entering the program volunt

in units in 2003. 

TOTAL 2003 ALLOCATION 9,541,085Banked Allowances 8,646,818 Banked Allowances are those held over from 1995 through 2002, w

compliance in 2003 or any future year. 

TOTAL 2002 ALLOWABLE 18,187,903

Source: EPA, Acid Rain Program 2003 Progress Report, Document EPA-430-R-04-011, November 2004, Figure 3.

206
Table 12.1 – Renewable Energy Impacts Calculation 

Conversion Formula: Step 1 Capacity (A) x Capacity Factor (B) x Annual Hours (C) = Annua

Step 2 Annual Electricity Generation (D) x Competing Heat Rate (E) = Step 3 Annual Output (F) x Emissions Coefficient (G) = Annual Emissi

Technology Wind Geothermal Biomass Hydropower 

(A) Capacity (kW) 8,181,033 2,189,957 6,417,795 79,103,834 

(B) Capacity Factor (%) 36.0% 90.0% 80.0% 44.2% (C) Annual Hours 8,760 8,760 8,760 8,760 (D) Annual Electricity Generation (kWh) 25,799,706,093 17,265,620,227 44,975,908,630 306,239,675,812 333

(E) Competing Heat Rate (Btu/kWh) 10,107 10,107 10,107 10,107 (F) Annual Output (Trillion Btu) 261 175 455 3,095 (G) Carbon Coefficient (MMTCB/Trillion Btu) 0.01783 0.01783 0.01783 0.01783 (H) Annual Carbon Displaced (MMTC) 4.649 3.111 8.105 55.187 

Sources: Capacity: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table A16, 2005.

Capacity factors: Hydropower calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), 

on DOE, Renewable Energy Technology Characterizations, EPRI TR-109496, 1997, and program data.Heat Rate: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table A6.

Carbon Coefficient: DOE, GPRA2003 Data Call, Appendix B, page B-16, 2003. Notes: Capacity values exclude combined-heat-and-power (CHP) data but include end-use sector (industrial and commercial) non-CHP data.

Competing heat rate from Fossil-Fueled Steam-Electric Plants heat rate. 

207
Table 12.2 – Number of Home Electricity Needs Met Calculation 

Conversion Formula: Step 1 Capacity (A) x Capacity Factor (B) x Annual Hours (C) = Annual Ele

Step 2 Annual Electricity Generation (D) / Average Consumption (E) = Num

Technology Wind Geothermal Biomass Hydropower (A) Capacity (kW) 8,181,033 2,189,957 6,417,795 79,103,834 16

(B) Capacity Factor (%) 36.0% 90.0% 80.0% 44.2% 2(C) Annual Hours 8,760 8,760 8,760 8,760 (D) Annual Electricity Generation (kWh) 25,799,706,093 17,265,620,227 44,975,908,630 306,239,675,812 333,05

(E) Average Annual Household Electricity Consumption (kWh) 11,586 11,586 11,586 11,586 1(F) Number of Households 2,226,809 1,490,220 3,881,935 26,431,984 2

Sources: Capacity: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table A16, 2005. 

Capacity factors: Hydropower calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), 

based on DOE, Renewable Energy Technology Characterizations, EPRI TR-109496, 1997, and program data. 

Household electricity consumption: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February), Tables A4 and A

Notes: Capacity values exclude combined-heat-and-power (CHP) data but include end-use sector (industrial and commercial) non-CHP data.

208
Table 12.3 – Coal Displacement Calculation 

Conversion Formula: Step 1 Capacity (A) x Capacity Factor (B) x Annual Hours (C) = Annual Electricity Genera

Step 2 Annual Electricity Generation (D) x Conversion Efficiency (E) = Total Output (F) Step 3 Total Output (F) / Fuel Heat Rate (G) = Quantity Fuel (H) 

Technology Wind Geothermal Biomass Hydropower 

(A) Capacity (kW) 8,181,033 2,189,957 6,417,795 79,103,834 

(B) Capacity Factor (%) 36.0% 90.0% 80.0% 44.2% (C) Annual Hours 8,760 8,760 8,760 8,760 

(D) Annual Electricity Generation (kWh) 25,799,706,093 17,265,620,227 44,975,908,630 306,239,675,812 3(E) Competing Heat Rate (Btu/kWh) 10,107 10,107 10,107 10,107 (F) Total Output (Btu) 260,757,629,480,278 174,503,623,632,874 454,571,508,527,161 3,095,164,403,427,280 3,366,1(G) Coal Heat Rate (Btu per short ton) 20,381,000 20,381,000 20,381,000 20,381,000 (H) Coal (short tons) 12,794,153 8,562,074 22,303,690 151,865,188 Sources: Capacity: EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table A16, 2005.

Capacity factors: Hydropower calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table A16. All others based on DOE, Renewable Energy Technology Characterizations, EPRI TR-109496, 1997 

and Program data. Conversion Efficiency: EIA, Annual Energy Review 2003, DOE/EIA-0384(2003) (Washington, D.C., September 2004), Table A6. 

Heat Rate: Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table H1. Notes:

Capacity values exclude combined-heat-and-power (CHP) data but include end-use sector (industrial and commercial) non-CHP data.

209
Table 12.4 – National SO2 and Heat Input Data

1980 1985 1990 1995 200

SO2 (lbs) 34,523,334,000 32,184,330,000 31,466,566,000 23,667,789,600 22,404,913,80

Heat (MMBtu) 17,838,745,941 18,414,433,865 19,684,094,492 21,874,579,916 25,603,420,99

SO2 Heat Factor (lb/MMBtu) 1.935 1.748 1.599 1.082 0.87

Source: EPA, Clean Air Markets Web site - Data and Maps, Emissions section, http://cfpub.epa.gov/gdm/

210
Table 12.5 – SO2, NOx, CO2 Emission Factors for Coal Fired 

and Non-Coal Fired Title IV Affected Units 

1996 1997 1998 1999 2000 2001 2002

SO2 (lbs/mmBtu)  Coal 1.241 1.245 1.222 1.166 1.036 1.008 0.976 Non-Coal 0.246 0.256 0.318 0.267 0.200 0.220 0.126 Total 1.096 1.093 1.058 0.999 0.875 0.843 0.794NOx (lbs/mmBtu)  Coal 0.568 0.559 0.532 0.487 0.444 0.425 0.408 Non-Coal 0.221 0.234 0.251 0.244 0.210 0.176 0.128 Total 0.518 0.509 0.481 0.442 0.399 0.373 0.348CO2 (lbs/mmBtu)  Coal 206.377 205.537 205.677 205.586 205.646 205.627 205.672 Non-Coal 132.731 130.804 131.685 132.001 133.110 130.159 126.858 Total 195.682 194.056 192.256 191.956 191.672 189.809 188.813Source: EPA, Acid Rain Program Compliance Report 2001, Emission Scorecard, updated April 2003, Table 1, 

http://www.epa.gov/airmarkets/emissions/score01/index.html, and EPA, Clean Air Markets Web site - Data and Maps, Emissions section, 

http://cfpub.epa.gov/gdm/

211
Table 12.6a – Sulfur Dioxide, Nitrogen Oxide, and Carbon Dioxide 

Emission Factors, 2003 - Electricity Generators 

 

Emission Factors 

Fuel 

Boiler Type/ 

Firing 

Configuration 

Sulfur 

Dioxide 1 Nitrogen 

Oxides 2

Carbon 

Dioxide 3

Electricity Generators 

Coal and Other Solid Fuels lbs per ton lbs per ton 

lbs per 106

Btu 

 Petroleum Coke4

 fluidized bed5 39.0 x S 21 225.13

all others 39.0 x S 21 225.13

 Refuse all types 3.9 5 199.82

 Wood all types 0.08 1.5 0

 

Petroleum and Other Liquid Fuels 

lbs per 103

gal 

lbs per 103

gal 

lbs per 106

Btu 

 Residual Oil6

 tangential 157.0 x S 32 173.72

vertical 157.0 x S 47 173.72

all others 157.0 x S 47 173.72

 Distillate Oil6

 all types 150.0 x S 24 161.27

Methanol all types 0.05 12.4 138.15

 Propane (liquid) all types 86.5 19 139.04

Coal-Oil Mixture all types 185.00 x S 50 173.72

 

Natural Gas and Other Gaseous 

Fuels lbs per 106

 cf 

lbs per 106

cf 

lbs per 106

Btu 

 Natural Gas tangential 0.6 170 116.97

 all others 0.6 280 116.97

 Blast Furnace Gas all types 950 280 116.97

 

Source: EIA, Electric Power Annual 2003, DOE/EIA-0348(2003) (Washington, D.C., December 2004) Table A1 

Notes: 1

 Uncontrolled sulfur dioxide emission factors. "x S" indicates that the constant must be multiplied by the percentage 

(by weight) of sulfur in the fuel. Sulfur dioxide emission estimates from facilities with flue gas desulfurization equipment 

are calculated by multiplying uncontrolled emission estimates by one minus the reported sulfur removal efficiencies. 

Sulfur dioxide emission factors also account for small quantities of sulfur trioxide and gaseous sulfates. 

2

 Parenthetic values are for wet bottom boilers; otherwise dry bottom boilers. If bottom type is unknown, dry bottom is 

assumed. Emission factors are for boilers with a gross heat rate of 100 million Btu per hour or greater. 

3

 Uncontrolled carbon dioxide emission estimates are reduced by 1% to account for unburned carbon. 

4

 Emission factors for petroleum coke are assumed to be the same as those for anthracite. If the sulfur content of 

petroleum coke is unknown, a 6 percent sulfur content is assumed. 

5

 Sulfur dioxide emission estimates from fluidized bed boilers assume a sulfur removal efficiency of 90%. 

6

 Oil types are categorized by Btu content as follows: heavy (greater than or equal to 144,190 Btu per gallon), and light 

(less than 144,190 Btu per gallon). cf = Cubic Feet. gal = U.S. Gallons. lbs = Pounds. 

212
Table 12.6b – Sulfur Dioxide, Nitrogen Oxide, and Carbon 

Dioxide Emission Factors, 2003 - Combined Heat and Power 

Producers 

 

Emission Factors 

Fuel 

Boiler Type/ 

Firing 

Configuration 

Sulfur 

Dioxide 1

Nitrogen 

Oxides 2

Carbon 

Dioxide 3

Coal and Other Solid Fuels lbs per ton 

lbs per 

ton 

lbs per 106

Btu 

Peat. all types 30.00 x S 12 0

Agricultural Waste all types 0.08 1.2 0

Black Liquor all types 7 1.5 0

Chemicals all types 7 1.5 0

Closed Loop Biomass all types 0.08 1.5 0

Internal all types 0.08 1.5 0

Liquid Acetonitrile Waste all types 7 1.5 150.76

Liquid Waste all types 2.8 2.3 163.29

Municipal Solid Waste all types 1.7 5.9 189.48

Petroleum Coke all types 39.00 x S 14 225.13

Pitch all types 30.00 x S 11.1 0

RailRoad Ties all types 0.08 1.5 0

Red Liquor. all types 7 1.5 0

Sludge all types 2.8 5 0

Sludge Waste all types 2.8 5 0

Sludge Wood all types 2.8 5 0

Spent Sulfite Liquor all types 7 1.5 0

Straw all types 0.08 1.5 0

Sulfur all types 7 0 0

Tar Coal all types 30.00 x S 11.1 0

Tires all types 38.00 x S 21.7 0

Waste Byproducts all types 1.7 2.3 163.29

Waste Coal all types 38.00 x S 21.7 0

Wood/Wood Waste all types 0.08 1.5 0

 

Petroleum and Other Liquid Fuels 

lbs per 103

gal 

lbs per 

103

 gal 

lbs per 106

Btu 

 Heavy Oil4

 all types 157.00 x S 47 173.72

 Light Oil4

 all types 142.00 x S 20 159.41

 Diesel all types 142.00 x S 20 161.27

 Kerosene all types 142.00 x S 20 159.41

 Butane (liquid) all types 0.09 21 143.2

 Fish Oil all types 0.5 12.4 0

 Methanol all types 0.5 12.4 138.15

 Oil Waste all types 147.00 x S 19 163.61

 Propane (liquid) all types 0.5 19 139.04

 Sludge Oil all types 147.00 x S 19 0

 Tar Oil all types 162.70 x S 67 0

 Waste Alcohol all types 0.5 12.4 138.15

 

213
Natural Gas and Other Gaseous 

Fuels lbs per 106 cf

lbs per 

106 cf 

lbs per 106

Btu 

 Natural Gas all types 0.6 280 116.97

 Butane (Gas) all types 0.6 21 143.2

 Hydrogen all types 0 550 0

 Landfill Gas all types 0.6 550 115.12

 Methane all types 0.6 550 115.11

 Other Gas all types 0.6 550 141.54

 Propane (Gas) all types 0.6 19 139.04

Source: EIA, Electric Power Annual 2003, DOE/EIA-0348(2003) (Washington, D.C., December 2004) 

Table A1

Notes: 

1 Uncontrolled sulfur dioxide emission factors. "x S" indicates that the constant must be multiplied by the 

percentage (by weight) of sulfur in the fuel. Sulfur dioxide emission estimates from facilities with flue gas 

desulfurization equipment are calculated by multiplying uncontrolled emission estimates by one minus the 

reported sulfur removal efficiencies. Sulfur dioxide emission factors also account for small quantities of 

sulfur trioxide and gaseous sulfates. 

2

 Parenthetic values are for wet bottom boilers; otherwise dry bottom boilers. If bottom type is unknown, 

dry bottom is assumed. Emission factors are for boilers with a gross heat rate of 100 million Btu per hour 

or greater. 

3 Uncontrolled carbon dioxide emission estimates are reduced by 1% to account for unburned carbon. 4 Oil types are categorized by Btu content as follows: heavy (greater than or equal to 144,190 Btu per 

gallon), and light (less than 144,190 Btu per gallon). cf = Cubic Feet. gal = U.S. Gallons. lbs = Pounds. 

214
Table 12.7 – Global Warming Potentials (GWP)

(100-year time horizon) Gas GWP 

SAR 

Carbon dioxide (CO2) 1Methane (CH4)

1 21

Nitrous oxide (N2O) 310

HFC-23 11,700HFC-32 650HFC-125 2,800HFC-134a 1,300HFC-143a 3,800HFC-152a 140HFC-227ea 2,900HFC-236fa 6,300HFC-4310mee 1,300CF4 6,500

C2F6 9,200

C4F10 7,000

C6F14 7,400SF6 23,900 

Source: EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003, EPA 430-R-05-004 (PUBLIC DRAFT FEBRUARY 2

Notes: The GWP of a greenhouse gas is the ratio of global warming, or radiative forcing – both direct and indirect – from one unit mass of a gre

unit mass of carbon dioxide over a period of time. GWP from Intergovernmental Panel and Climate Change (IPCC) Second Assessment Report (SAR) and Third Assessment Report (TAR

Although the GWPs have been updated by the IPCC, estimates of emissions presented in this report use the GWPs from the Second As

UNFCCC reporting guidelines for national inventories were updated in 2002, but continue to require the use of GWPs from the SAR so t

aggregated greenhouse gas emissions for 1990 through 2001 are consistent with estimates developed prior to the publication of the TAR

international reporting standards under the UNFCCC, official emission estimates are reported by the United States using SAR GWP valu

1 The methane GWP includes direct effects and those indirect effects due to the production of tropospheric ozone and stratospheric wate

The indirect effect due to the production of CO2 is not included. 

215
Table 12.8 – Approximate Heat Content of Selected 

Fuels for Electric Power Generation Fossil Fuels 1Residual Oil (million Btu per barrel) 6.287Distillate Oil (million Btu per barrel) 5.825Natural Gas (Btu per million cubic ft) 1,020Coal (million Btu per Short Ton) 20.381Biomass Materials 2 Switchgrass Btu per pound 7,341Bagasse, Btu per pound 6,065Rice Hulls, Btu per pound 6,575Poultry Litter, Btu per pound 6,187Solid wood waste, Btu per pound 6-8,000

Sources: 1. EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., February 2005), Table H1. 2. Animal Waste Screening Study, Electrotek Concepts, Inc., Arlington, VA. June 2001. 

216
Table 12.9 – Approximate Heat Rates for Electricity 

(Btu per Kilowatthour) 

1980 1990 2000 2001 2002 2003

Fossil-Fueled Steam-Electric Plants1 10,388 10,402 10,201 10,146 10,119 10,107Nuclear Steam-Electric Plants2 10,908 10,582 10,429 10,448 10,439 10,439Geothermal Energy Plants3 21,639 21,096 21,017 21,017 21,017 21,017Source: EIA, Annual Energy Review 2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Table A6

Notes: 

1 Through 2000, used as the thermal conversion factor for wood and waste electricity net generation at electric utilities. For all years, us

conversion factor for hydroelectric, solar, and wind electricity net generation. Through 2000, heat rates are for fossil-fueled steam-elec

utilities. For 2001 and 2002, heat rates are for fossil-fueled steam-electric plants at electric utilities and independent power producers. F

for all fossil-fueled plants at electric utilities and independent power producers 

2 Used as the thermal conversion factor for nuclear electricity net generation. 3 Used as the thermal conversion factor for geothermal electricity net generation 

217
Table 12.10 – Heating Degree Days by Month

1980 1990 2000 2001 2002 2003 2004 Normal1

January 887 728 886 935 778 940 957 917February 831 655 643 725 670 819 769 732March 680 535 494 669 624 564 487 593April 338 321 341 302 282 351 302 345May 142 184 115 115 185 162 NA 159June 49 29 29 29 23 39 NA 39July 5 6 12 8 3 2 NA 

9

August 10 10 12 6 8 2 NA 15September 54 56 69 71 38 59 NA 77October 316 246 244 267 299 252 NA 282November 564 457 610 400 561 477 NA 539December 831 789 1,005 696 813 773 NA 817Total 4,707 4,016 4,460 4,223 4,284 4,440 NA 4,524Source: EIA, Annual Energy Review 2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Table 1.7Notes: 1 Based on calculations of data from 1971-2000

Data exclude Alaska and Hawaii. Beginning in 2002, data are weighted by the estimated 2000 population. The population-weighted stafigures are aggregated into Census divisions and the national average. 

218
Table 12.11 – Cooling Degree Days by Month

1980 1990 2000 2001 2002 2003 2004 Normal1

January 9 15 10 3 8 2 5 

9

February 4 14 10 12 6 6 5 

8

March 13 21 25 11 17 20 26 18April 23 29 28 37 53 38 41 30May 95 86 131 114 92 106 NA 97June 199 234 221 220 242 196 NA 213July 374 316 284 302 369 334 NA 321August 347 291 302 333 331 332 NA 290September 192 172 156 138 202 155 NA 155October 42 57 50 46 57 64 NA 53November 10 16 8 18 11 24 NA 15December 5 9 4 11 5 4 NA 

8

Total 1,313 1,260 1,229 1,245 1,393 1,281 NA 1,215Source: EIA, Annual Energy Review 2003, DOE/EIA-0384 (2003) (Washington, D.C., September 2004), Table 1.8Notes: 1 Based on calculations of data from 1971-2000

Data exclude Alaska and Hawaii. Beginning in 2002, data are weighted by the estimated 2000 population. The population-weighted staaggregated into Census divisions and the national average. NA = Not Available 

219
F1147-E(12/2004) 

REPORT DOCUMENTATION PAGE Form Approved 

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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

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2. REPORT TYPE

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3. DATES COVERED (From - To)

 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Power Technologies Energy Data Book – Third Edition 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

 NREL/TP-620-37930 

5e. TASK NUMBER

ASA4.6065 

6. AUTHOR(S)

Compiled by J. Aabakken 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

NREL/TP-620-37930 

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

This report, prepared by NREL’s Energy Analysis Office, includes up-to-date information on power technologies, 

including complete technology profiles. The data book also contains charts on electricity restructuring, power technology 

forecasts, electricity supply, electricity capability, electricity generation, electricity demand, prices, economic indicators,

environmental indicators, and conversion factors. 

15. SUBJECT TERMS

data book; power technologies; electricity restructuring; power technology forecasts and comparisons; electricity 

supply; electricity capability; electricity generation; electricity demand; prices; economic indicators; environmental 

indicators; conversion factors; Jørn Aabakken. 

16. SECURITY CLASSIFICATION OF: 19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified

c. THIS PAGE 

Unclassified

17. LIMITATION 

OF ABSTRACT

UL 

18. NUMBER 

OF PAGES 

19b. TELEPHONE NUMBER (Include area code)

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18