Power Technologies Energy Data Book 

August 2006 • NREL/TP-620-39728 

Fourth Edition 
Power Technologies 

Energy Data Book 

Fourth Edition 

Compiled by J. Aabakken 

Prepared under Task No. WUA3.1000 

Technical Report

NREL/TP-620-39728 

August 2006 

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov

Operated for the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
NOTICE

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any 

warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or

usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not 

infringe privately owned rights. Reference herein to any specific commercial product, process, or service by

trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement,

recommendation, or favoring by the United States government or any agency thereof. The views and

opinions of authors expressed herein do not necessarily state or reflect those of the United States

government or any agency thereof. 

Available electronically at http://www.osti.gov/bridge

Available for a processing fee to U.S. Department of Energy

and its contractors, in paper, from: 

U.S. Department of Energy

Office of Scientific and Technical Information 

P.O. Box 62 

Oak Ridge, TN 37831-0062

phone: 865.576.8401 

fax: 865.576.5728 

email: mailto:reports@adonis.osti.gov

Available for sale to the public, in paper, from: 

U.S. Department of Commerce 

National Technical Information Service 

5285 Port Royal Road 

Springfield, VA 22161 

phone: 800.553.6847 

fax: 703.605.6900 

email: orders@ntis.fedworld.gov

online ordering: http://www.ntis.gov/ordering.htm

Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste
Table of Contents 

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

2.0 Technology Profiles 

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

Geothermal.............................................................................................................10 

Concentrating Solar Power ....................................................................................18 

Photovoltaics..........................................................................................................23 

Wind Energy ..........................................................................................................33 

Hydrogen................................................................................................................40 

Advanced Hydropower ..........................................................................................44 

Building Technologies...........................................................................................49 

Reciprocating Engines ...........................................................................................60 

Microturbines.........................................................................................................64 

Fuel Cells ...............................................................................................................68 

Batteries .................................................................................................................73 

Advanced Energy Storage......................................................................................79 

Superconducting Power Technology .....................................................................81 

Thermally Activated Technologies........................................................................86 

3.0 Electricity Restructuring 

3.1 States with Competitive Electricity Markets .............................................89 

3.2 States with System Benefit Charges (SBC)...............................................90 

3.3 States with Renewable Portfolio Standards (RPS) ....................................93 

3.4 States with Net Metering Policies..............................................................99 

3.5 States with Environmental Disclosure Policies .......................................108 

3.6 Green Power Markets ..............................................................................109 

3.7 States with Utility Green Pricing Programs.............................................112 

3.8 Competitive Green Power Offerings and Renewable 

Energy Certificates...................................................................................127 

3.9 Federa Agency Purchases of Green Power..............................................137 

3.10 State Incentive Programs .........................................................................138 

4.0 Forecasts/Comparisons 

4.1 Projections of Renewable Electricity Net Capacity.................................143 

4.2 Projections of Renewable Electricity Net Generation .............................144 

4.3 Projections of Renewable Electricity Carbon Dioxide 

Emissions Savings ...................................................................................145

5.0 Electricity Supply 

5.1 U.S. Total and Delivered Energy (Overview) .........................................147 

5.2 Electricity Flow Diagram.........................................................................149 

5.3 Electricity Overview ................................................................................151 

5.4 Consumption of Fossil Fuels by Electric Generators ..............................152 

5.5 Electric Power Sector Energy Consumption ...........................................153 

iii 
5.6 Fossil Fuel Generation by Age of Generating Units................................155 

5.7 Nuclear Generation by Age of Generating Units ....................................156 

5.8 Operational Renewable Energy Generating Capacity ............................157 

5.9 Number of Utilities by Class of Ownership and Nonutilities..................158 

5.10 Top 10 U.S. Investor-Owned Utilities .....................................................159 

5.11 Top 10 Independent Power Producers Worldwide (2001) ......................160 

5.12 Utility Mergers and Acquisitions.............................................................161 

5.13a North American Electric Reliability Council Map for the 

United States ............................................................................................162 

5.13b Census Regions Map................................................................................163 

6.0 Electricity Capability 

6.1 Electric Net Summer Capability ..............................................................165 

6.2 Electric-Only Plant Net Summer Capability............................................166 

6.3 Combined-Heat-and-Power Plant Net Summer Capability .....................167 

6.4 Regional Noncoincident Peak Loads and Capacity Margin ....................168 

6.5 Electric Generator Cumulative Additions and Retirements.....................169 

6.6 Transmission and Distribution Circuit Miles...........................................170 

7.0 Electricity Generation 

7.1 Electricity Net Generation .......................................................................171 

7.2 Net Generation at Electric-Only Plants ...................................................172 

7.3 Electricity Generation at Combined-Heat-and-Power Plants ..................173 

7.4 Generation and Transmission/Distribution Losses ..................................174 

7.5 Electricity Trade.......................................................................................175 

8.0 Electricity Demand 

8.1 Electricity Sales .......................................................................................177 

8.2 Demand-Side Management......................................................................178 

8.3 Electric Utility Sales, Revenue, and Consumption by

Census Division and State ......................................................................179 

9.0 Prices 

9.1 Price of Fuels Delivered to Electric Generators ......................................181 

9.2 Electricity Retail Sales.............................................................................182 

9.3 Prices of Electricity Sold ........................................................................183 

9.4 Revenue from Electric Utility Retail Sales by Sector..............................184 

9.5 Revenue from Sales to Ultimate Consumers by Sector, Census 

Division, and State ..................................................................................185 

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

Investor-Owned and Publicly Owned Utilities........................................187

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

Electric Utilities .......................................................................................188 

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

Generator and Nongenerator Electric Utilities ........................................189 

9.7 Environmental Compliance Equipment Costs.........................................190 

iv 
10.0 Economic Indicators 

10.1 Price Estimates for Energy Purchases......................................................191 

10.2 Economy-Wide Indicators .......................................................................192 

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

Generator and Investor-Owned Electric Utilities ....................................193 

11.0 Environmental Indicators 

11.1 Emissions from Electricity Generators ....................................................195 

11.2 Installed Nameplate Capacity of Utility Steam-Electric Generators with 

Environmental Equipment .......................................................................197 

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

Emissions from Electric Generators ........................................................198 

11.4 Origin of 2004 Allowable SO2 Emissions Levels....................................199 

12.0 Conversion Factors 

12.1 Renewable Energy Impacts Calculation ..................................................201 

12.2 Number of Home Electricity Needs Met Calculation..............................202 

12.3 Coal Displacement Calculation................................................................203 

12.4 National SO2 and Heat Input Data ...........................................................204 

12.5 SO2, NOx, CO2 Emission Factors for Coal-Fired and Noncoal-Fired 

Title IV Affected Units ............................................................................205 

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

Electricity Generators ..............................................................................206 

12.6b Nitrogen Oxide Uncontrolled Emission Factors, 

Electricity Generators ..............................................................................208 

12.6c Uncontrolled Carbon Dioxide Emission Factors, 

Electricity Generators ..............................................................................210 

12.7 Global Warming Potentials (GWP) .........................................................211 

12.8 Approximate Heat Content of Selected Fuels for Electric 

Power Generation.....................................................................................212 

12.9 Approximate Heat Rates for Electricity...................................................213 

12.10 Heating Degree Days by Month ..............................................................214 

12.11 Cooling Degree Days by Month ..............................................................215 

13.0 Geographic Information System (GIS) Maps .....................................................217 

v 
1.1 - Introduction 

About the Power Technologies Energy Data Book (PTEDB), Fourth 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 

policy makers 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. 

New for this fourth edition of the PTEDB is Chapter 13, which features Geographic 

Information System (GIS) maps. One set of maps shows the natural resource (biomass, 

geothermal, solar, and wind) overlaid with the national transmission grid and the major

electricity load centers. The other set of maps shows the current installed capacity

(biomass, geothermal, concentrating solar power, and wind), as well as a bar chart 

indicating the historic trend of generating capacity for the state. 

The PTEDB is organized into 13 chapters: 

Chapter 1 - Introduction 

Chapter 2 – Technology profiles 

Chapter 3 – Electricity restructuring

Chapter 4 – Forecasts/comparisons 

Chapter 5 – Electricity supply

Chapter 6 – Electricity capability

Chapter 7 – Electricity generation 

Chapter 8 – Electricity demand 

Chapter 9 – Prices 

Chapter 10 – Economic indicators 

Chapter 11 – Environmental indicators 

Chapter 12 – Conversion factors 

Chapter 13 – Geographic Information System (GIS) maps. 

The sources used for the Power Technologies Energy Data Book represent the latest 

available data. 

This edition updates the same type of information provided 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. 

 1
This fourth edition of the Power Technologies Energy Data Book, as well as previous 

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

The PTEDB may be downloaded as a single PDF file, individual chapters, or table 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. 

 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 gasesGHGs) 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 compared to fossil energy without carbon sequestration, such as coal, oil or natural 

gas. 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 costeffective 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, as is true for coal. 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 9,700 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 nonhydroelectric 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. 

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 to in the wood-processing and pulp-and-paper sectors 

and increased supply of power to the grid. 

• The combination of low natural gas prices, improved economies of scale in combined cycle palns, and 

withdrawal of incentives in the late 1980s, led to annual installations declining from about 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 (draft update, 

September 2005). 

5
Biomass 

Market Data 

Cumulative Generating Capability, by Type Source: Energy Information Administration (EIA), EIA, Annual Energy Review 200(MW) (Washington, D.C., August 2005), Tables 8.11a and 8.11c, and world data from U

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

1980 1985 1990 1995 1996 1997 1998 1999 2000 

U.S. Electric Power Sector Municipal Solid Waste1 N/A 151 1,852 2,733 2,600 2,528 2,636 2,614 2,78

Wood and Other Biomass2 78 200 964 1,451 1,425 1,452 1,438 1,484 1,48

U.S. Cogenerators3

 Municipal Solid Waste1 659 786 998 1,062 1,058 1,046 1,09

Wood and Other Biomass2 4,585 5,298 5,382 5,472 5,364 5,311 4,65

U.S. Total  Municipal Solid Waste1 NA 151 2,511 3,519 3,598 3,590 3,694 3,660 3,88

Wood and Other Biomass2 78 200 5,549 6,750 6,808 6,924 6,802 6,795 6,14

 Biomass Total 78 351 8,061 10,269 10,405 10,515 10,495 10,454 10,02Rest of World Total4 29,505 

World 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 adddue to rounding. 

6
U.S. Annual Installed Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 

Generating Capability, by 2003. Type (MW)

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

Capability, by Type6 (MW) 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 databases. 1 2003 data not complete as REPiS database is updated through 2002. 

2 Agricultural residues, cannery wastes, nut hulls, fruit pits, nut shells3 Biogas, alcohol (includes butahol, ethanol, and methanol), bagasse, hydrogen, landfill gas, livestock manure, wood gas (from wood 4 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 accounted 

have no specific online date. 

7
Generation from Source: EIA, Annual Energy Review 2003, Tables 8.2a and 8.2c, and world data from United Natio

Cumulative Capacity, by Program, World Energy Assessment, 2000, Table 7.25. Type (Million kWh)

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 20

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 17,

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

U.S. Cogenerators3

 Municipal Solid Waste1 2,904 4,079 4,834 5,312 5,485 5,460 5,540 4,543 5,

Wood and Other Biomass2 26,939 30,636 30,307 30,480 29,694 29,787 30,294 28,629 31,

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

Wood and Other Biomass2 275 743 32,266 36,521 36,800 36,948 36,338 37,041 37,595 35,200 38,

 Biomass Total 433 1,383 45,415 56,926 57,712 58,658 58,786 59,613 60,726 56,964 61,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 Source: EIA, Annual Energy Review 2004, Tables 8.4b and 8.4c 

Consumption for Electricity Generation (Trillion Btu) 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 20

Electric-Power Sector 4.5 14.4 285.9 388.0 397.3 408.3 412.0 415.5 420.7 430.4 4Commercial Sector1 16.7 22.3 32.1 34.3 32.7 33.5 26.5 22.6 

Industrial Sector1 351.0 385.3 407.1 380.7 362.0 373.0 378.8 379.6 4Total Biomass 4.5 14.4 653.5 795.6 836.5 823.3 806.8 822.0 825.9 832.6 1,0Data include wood (wood, black liquor, and other wood waste) and waste (municipal solid waste, landfill gas, sludge waste, tires, agand 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. 

Efficiency 1980 1990 19951 2000 2005 2010 20

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 20

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 20

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 that cofired cost characteristics represent only the biomass portion of costs for capital and incremental costs above conve

Operations & Maintenance (O&M), and assume $9.14/dry tonne biomass and $39.09/tonne coal, a heat input from biomass at 1that variable O&M includes an SO2 credit valued at $110/tonne SO2. No cofiring COE is reported in the RETC. 

9
Geothermal Energy
 

Technology Description 

Geothermal energy is heat from within the Earth. Hot water or steam are used to produce electricity or 

applied directly for space heating and industrial processes. This energy can offset the emission of 

carbon dioxide from conventional fossil-powered electricity generation, industrial processes, building 

thermal systems, and other applications. 

System Concepts 

• Geophysical, geochemical, and 

geological exploration locates resources to 

drill, including highly permeable hot 

reservoirs, shallow warm groundwater, hot 

impermeable rock masses, and highly 

pressured hot fluids. 

• Well fields and distribution systems 

allow the hot fluids to move to the point of 

use, and afterward, back to the earth. 

• Utilization systems may apply the heat 

directly or convert it to another form of 

energy such as electricity. 

Representative Technologies 

• Exploration technologies identify 

geothermal reservoirs and their fracture 

systems; drilling, reservoir testing, and modeling optimize production and predict useful lifetime; steam 

turbines use natural steam or hot water flashed to steam to produce electricity; binary conversion 

systems produce electricity from water not hot enough to flash. 

• Direct applications use the heat from geothermal fluids without conversion to electricity. 

Geothermal heat pumps use the shallow earth as a heat source and heat sink for heating and cooling 

applications. 

• Coproduction, the recovery of minerals and metals from geothermal brine, is being pursued. Zinc is 

recovered at the Salton Sea geothermal field in California. 

Technology Applications 

• With improved technology, the United States has a resource base capable of producing up to 100 

GW of electricity at less than 5¢/kWh. 

• Hydrothermal reservoirs are being used to produce electricity with an online availability of up to 

97%; advanced energy-conversion technologies are being implemented to improve plant thermal 

efficiency. 

• Direct-use applications are successful throughout the western United States and provide heat for 

space heating, aquaculture, greenhouses, spas, and other applications. 

• Geothermal heat pumps continue to penetrate markets for heating/cooling (HVAC) services. 

Current Status 

• The DOE Geothermal Program sponsored research that won two R&D 100 Awards in 2003: 

Acoustic Telemetry Technology, which provides a high speed data link between the surface and the 

drill bit; and Low Emission Atmospheric Monitoring Separator, which safely contains and cleans 

vented steam during drilling, well testing, and plant start-up. 

• A second pipeline to carry replacement water has been completed through the joint efforts of 

industry and federal, state, and local agencies. This will increase production and extend the lifetime of 

The Geysers Geothermal Field in California. The second pipeline adds 85 MW of capacity. 

10
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. 

• With approval of the federal production tax credit and with support from state-level renewable 

portfolio standards, U.S. geothermal power is poised to double in capacity within the next couple of 

years. 

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. 

• Costs at the best sites are competitive at today’s energy prices – and investment is limited by 

uncertainty in prices; lack of new, confirmed resources; high front-end costs; and lag time between 

investment and return. 

• Improvements in cost and accuracy of resource exploration and characterization can lower the 

electricity cost; demonstration of new resource concepts, such as enhanced geothermal systems, would 

allow a large expansion of the U.S. use of hydrothermal when economics become favorable. 

11
Market Context 

• Hydrothermal reservoirs have an installed capacity of about 2,133 MW electric in the United States 

and about 8,000 MW worldwide. Direct-use applications have an installed capacity of about 600 MW 

thermal in the United States. About 300 MW electric are being developed in California, Nevada, and 

Idaho. 

• Geothermal will continue production at existing plants (2.1 GW) with future construction potential 

(100 GW by 2040). Direct heat will replace existing systems in markets in 19 western states. 

• By 2015, geothermal could provide about 10 GW, enough heat and electricity for 7 million homes; 

by 2020, an installed electricity capacity of 20,000 MW from hydrothermal plants and 20,000 MW 

from enhanced geothermal systems is projected. 

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

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

September 2005). 

12
Geothermal 

Market Data 

Cumulative Installed Source: U.S. electricity data from EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Wa

Capacity 2005), Table 8.11a; world totals from Renewable Energy World/July-August 2000, page 123, T

from UNDP World Energy Assessment 2000, Tables 7.20 and 7.25; 1997 world electricity and heat data from Stefansson and Fridleifsson 1998, “Geothermal Energy: European and World-w

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Electricity (MWe) 

U.S. 909 1,580 2,666 2,968 2,893 2,893 2,893 2,846 2,793 2,216 

Rest of World 1,191 3,184 3,166 3,829 5,128 5,346 5,181 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 7,799 World Total 1,950 7,072 8,064 8,664 9,704 11,000 17,175 

Cumulative Installed Source: International Geothermal Association, http://iga.igg.cnr.it/index.php Capacity 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Electricity (MWe) 

U.S. 2,775 2,817 2,228 

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 3,766 

Rest of World 6,730 11,379 

World Total 8,604 15,145 

13
Annual Installed Electric Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 2003. 

Capacity (MWe) 

1980 1985 1990 1995 1996 1997 1998 1999 2000 

 U.S. 251.0 352.9 48.6 36.0 59.9 

Cumulative Installed Electric Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 2003. Capacity (MWe) 

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 Source: Lund and Freeston, World-Wide Direct Uses of Geothermal Energy 2000, Lund and 

Generation/Energy Production Use in the United States Update: 1995-1999, J. Lund, World Status of Geothermal Energy 

from Installed Capacity 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 Congreshttp://geothermal.stanford.edu/wgc2000/SessionList.htm, Kyushu-Tohoku, Japan, May 28-J

Cumulative Installed Capacity 

1980 1985 1990 1995 1996 1997 1998 1999 200

Electricity (MWe) 

U.S. 2,369 2,343 2,314 2,284 2,293 2,22 Rest of World 4,464 5,74

 World Total 3,887 4,764 5,832 6,833 7,97

Direct-Use Heat* (MWth) 

U.S. 4,20 Rest of World 12,97 World Total 1,950 7,072 8,064 8,664 16,209 17,17

14
Annual Generation/Energy Production from Cumulative Installed Capacity 

1980 1985 1990 1995 1996 1997 1998 1999 200

Electricity (Billion kWhe) 

U.S. 14.4 15.1 14.6 14.7 15.0 15 Rest of World 33

 World Total 49Direct-Use Heat* (TJ) U.S. 13,890 20,302 21,70

 Rest of World 98,551 141,707 163,43

World Total 86,249 112,441 162,009 185,13

* 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 Source: U.S. electricity data from EIA, Annual Energy Review 2004, DOE/EIA-0384(2

Cumulative Installed Capacity August 2005), Table 8.2a; world electricity totals from Renewable Energy World/July-A

Table 2; 1997 world electricity and U.S. and world direct-use heat data from Stefansso“Geothermal Energy: European and World-wide Perspective.” 1998 world totals from Assessment 2000, Table 7.25; 1995, 2000, and 2003 direct-use heat and 1999 electriInternational Geothermal Association, http://iga.igg.cnr.it/index.php. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Electricity (Billion kWhe) 

U.S. 5.1 9.3 15.4 13.4 14.3 14.7 14.8 14.8 14.1 13.7 Rest of World 8.9 7.7 3.6 6.6 29.0 31.2 35.2 World Total 14 17 19 20 43.8 46 49 49.3Direct-Use Heat (billion kWhth)U.S. 3.9 4.0 5.6 

Rest of World 

31.1 

World Total 31.2 40 53.0 

27.4 47.3

35.1 

15
Annual Geothermal Energy Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., A

Consumption for Electric Generation (Trillion Btu)

1980 1985 1990 1995 1996 199 1998 1999 2000 2

7 

U.S. 110 198 326 280 300 309 311 312 296 Rest of World World Total Annual U.S. Geothermal Heat Pump Source: EIA, Renewable Energy Annual 2004, DOE/EIA-0603(2004) (Washington, D.C

Shipments, by type (units) Table 58. 

1996 1997 1998 1999 2000 2001* 

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

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

Other non-ARI Rated 1995 838 991 1,327 1,714 2,138 1,554 N/A Totals 32,334 31,385 37,434 38,266 41,679 35,581 N/A 

* No survey was conducted for 2001. Capacity of U.S. Heat Pump Shipments Source: EIA, Renewable Energy Annual 2004, DOE/EIA-0603(2004) (Washington, D.C

(Rated Tons) Table 59. 

1996 1997 1998 1999 2000 2001* 

ARI-320 13,120 15,060 24,708 35,776 27,970 26,469 N/A ARI-325/330 113,925 92,819 110,186 98,912 153,947 130,132 N/A Other non-ARI Rated 1995 3,935 5,091 6,662 6,758 9,735 7,590 N/A Totals 130,980 112,970 141,556 141,446 191,652 164,191 N/A 1 One Rated Ton of Capacity equals 12,000 Btu's. 2 No survey was conducted for 2001. Annual U.S. Geothermal Heat Pump Source: EIA, Renewable Energy Annual 2004, DOE/EIA-0603(2003) (Washington, D.C

Shipments by Customer Type and 2003 Table 40, REA 2002 Table 40, REA 2001 Table 40, REA 2000 Table 38, REA 1Model Type (units) Table 40. 

1996 1997 1998 1999 2000 2001* 

Exporter 2,276 226 109 6,172 784 N/A Wholesale Distributor 21,444 29,181 14,377 9,193 9,804 N/A Retail Distributor 8,336 829 3,222 2,555 2,272 N/A Installer 18,762 25,302 18,429 24,917 20,491 N/A 

16
End User 689 657 994 66 63 N/A 

Others 13 1,727 1,135 6,259 2,167 N/A Total 51,520 57,922 38,266 49,162 35,581 N/A 

Annual U.S. Geothermal Heat Pump Shipments by Export & Census Region (units) Export Midwest Northeast South West Total 

Source: EIA, Renewable Energy Annual 2004, DOE/EIA-0603(2003) (Washington, D.C

2003 Table 39, REA 2002 Table 39, REA 2001 Table 39, REA 2000 Table 37, REA 19Table 39. 

1996 1997 1998 1999 2000 2001* 

4,090 2,427 481 6,303 1,220 N/A 

11,874 13,402 12,240 13,112 10,749 N/A 

6,417 9,280 5,403 6,044 4,138 N/A 

25,302 26,788 16,195 20,935 17,403 N/A 

3,837 6,025 3,947 2,768 2,071 N/A 

51,520 57,922 38,266 49,162 35,581 N/A 

Technology Performance 

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

Efficiency  Capacity Factor (%) Flashed Steam 

Binary Hot Dry Rock 

1980 1990 1995 

89 89 80 

2000 

92 92 81 

2005 

93 93 82 

2

Cost  Capital Cost ($/kW) Flashed Steam 

Binary Hot Dry Rock 

1980 1990 1995 

1,444 2,112 5,519 

2000 

1,372 1,994 5,176 

2005 

1,250 1,875 4,756 

2

114

 Fixed O&M ($/kW-yr) Flashed Steam 

Binary Hot Dry Rock 

96.4 87.4 

219 

87.1 78.5 

207 

74.8 66.8 

191 

17
Concentrating Solar Power
 

Technology Description 

Concentrating Solar Power (CSP) systems concentrate solar energy 50 to 10,000 times to produce hightemperature thermal energy, which is used to produce electricity for distributed or bulk generation 

process applications. 

System Concepts 

• In CSP systems, 

highly reflective suntracking mirrors produce 

temperatures of 400°C to 

800°C 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 solar-toelectric efficiencies for 

the system of up to 30%. 

• CSP technologies provide firm, nonintermittent electricity generation (peaking or intermediate load 

capacity) when coupled with storage. 

• Because solar-thermal technologies can yield extremely high temperatures, the technologies could 

some day be used for direct conversion (rather than indirect conversion through electrochemical 

reactions) of natural gas or water into hydrogen for future hydrogen-based economies. 

Representative Technologies 

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

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

fossil fuel to meet utility needs. Some of the new trough plants include thermal storage. Plant sizes can 

range from 1.0 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 

extremely efficiently to allow power production to match utility demand, even when the sun is not 

shining. Plant size can range from 30 to 200 MWe. 

• A dish/engine system 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 2-25 

kW in size and can be used individually or in small groups for distributed, remote, or village power; or 

in clusters (1-10 MWe) for utility-scale applications, including end-of-line support. They are easily 

hybridized with fossil fuel. 

Technology Applications 

• Nine parabolic trough plants, with a rated capacity of 354 MWe, have been operating in California 

since the 1980s. Trough system electricity costs of about 12¢-14¢/kWh have been demonstrated 

commercially. 

• Solar Two, a 10-MWe pilot power tower with three hours of storage, provided all the 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. 

18
Current Status 

• New commercial plants are being considered for California, Nevada, New Mexico, Colorado, and 

Arizona. A 1MW power plant began operation in Arizona in 2005. 

• The 10-MW Solar Two pilot power tower plant operated successfully near Barstow, California, 

leading to the first commercial plant being planned in Spain. 

• Operations and maintenance costs have been reduced through technology improvements at the 

commercial parabolic trough plants in California by 40%, saving plant operators $50 million. 

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. 

19
• 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%. 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 

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 2003$/kWh) for three CSP configurations are projected at: 

2003 2007 2012 2025 

Trough 11.3 6.4 5.4 N/A 

Power Tower 12.0 5.7 4.0 N/A 

Dish/Engine 40.0 20.0 N/A 6

 Source: Solar Energy Technologies Program Multiyear Technical Plan, NREL Report No. MP-520­

33875; DOE/GO-102004-1775. 

• Parabolic troughs have been commercialized and nine plants (354 MW total) have operated in 

California since the 1980s. 

• A 64-MW parabolic trough plant is under construction near Boulder City, Nevada. Nevada Power 

and Sierra Pacific Power will purchase the power to comply with the solar portion of Nevada’s 

renewable portfolio standard. 

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

World Bank considers CSP to be a primary candidate for Global Environment Facility funding. 

Market Context 

• There is currently 350 MW of CSP generation in the United States, all of it in Southern California's 

Mojave Desert. 

• Power purchase agreements have been signed for 800 MW of new dish/engine capacity in 

California. The plants are anticipated to come on-line within the next several years. Significant 

domestic and international interest will likely result in additional projects. 

• According to a recent study commissioned by the Department of Energy, CSP technologies can 

achieve significantly lower costs (below 6¢/kWh) at modest production volumes. 

• At Congress’ request, DOE scoped out what would be required to deploy 1,000MW of CSP in the 

Southwest United States. DOE is actively engaged with the Western Governors’ Association to map a 

strategy to deploy 1-4 GW of CSP in the Southwest by 2015. 

• A near-term to midterm opportunity exists to build production capacity in the United States for 

both domestic use and international exports. 

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

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

September 2005). 

20
Concentrating Solar Power 

Market Data 

U.S. Installations (electric Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 

only) Energy Technology Characterizations, EPRI TR-109496. Cumulative (MW) 1980 1985 1990 1995 1996 1997 1998 1999 

U.S. 0 24 274 354 364 364 364 36 Power Tower 0 10 0 0 10 10 10 1 Trough 0 14 274 354 354 354 354 35 Dish/Engine 0 0 0 0 0 0 0.125 0.12

Annual Generation from Source: EIA, Annual Energy Outlook 1998-2006, Table A16, Renewable Resources in the Cumulative Installed 4. Capacity (Billion kWh)

1990 1995 1996 1997 1998 1999 2000 2001 

U.S. 1* 0.82 0.90 0.89 0.89 0.87 0.49 0.54 

* Includes both solar thermal and less than 0.02 billion kilowatthours grid-connected photovoltaic generation. Annual U.S. Solar Source: EIA - Annual Energy Review 2004, Table 10.3 and Renewable Energy Annual 2004 T

Thermal Shipments (Thousand Square Feet) 

1980 198 1990 1995 1996 1997 1998 1999 2000 2001 

5 

Total1 19,398 NA 11,409 7,666 7,616 8,138 7,756 8,583 8,354 11,189 

Imports 235 NA 1,562 2,037 1,930 2,102 2,206 2,352 2,201 3,502 

Exports 1,115 NA 245 530 454 379 360 537 496 840 

1 Total shipments as reported by respondents include all domestic and export shipments and may include imports that sub

domestic or to foreign customers. No data are available for 1985. P = Preliminary 

21
Technology Performance 

Efficiency 

Capacity Factor (%) Solar to Electric Eff. (%) 

Source: Solar Energy Technologies Program Multiyear Technical Plan, NREL Report 

DOE/GO-102004-1775. 

2003 2005 2007 2012 2018 2025 

Power Tower 78 75 73 NA 72 NA 

Trough 28 39 56 56 NA NA 

Dish 24 NA 24 NA NA 50 

Power Tower 14 16 17 NA 18 NA 

Trough 13 13 16 17 NA NA 

Dish 20 NA 23 NA NA 26 

Cost* 

Total ($/kWe) O&M ($/kWh) Levelized Cost of Energy 

($/kWh) 

2003 2005 2007 2012 2018 2025 

Power Tower 6800 4100 3500 NA 2500 NA 

Trough 2805 3556 3422 2920 NA NA 

Dish NA NA NA NA NA NA 

Power Tower .04 .01 .01 NA .01 NA 

Trough .02 .01 .01 .007 NA NA Dish NA NA NA NA NA NA Power Tower .12 .06 .06 NA .04 NA 

Trough .11 .10 .06 .05 NA NA 

Dish .40 NA .20 NA NA .06 

22
Photovoltaics
 

Technology Description 

Solar photovoltaic (PV) 

arrays use semiconductor 

devices called solar cells to 

convert sunlight to 

electricity without moving 

parts and without 

producing fuel wastes, air 

pollution, or greenhouse 

gases. Using solar PV for 

electricity – and eventually 

using solar PV to produce 

hydrogen for fuel cells for 

electric vehicles, by 

producing hydrogen from 

water – will help reduce carbon dioxide emissions 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., semitransparent solar canopy). The DC output from PV can be 

conditioned into grid-quality AC electricity, or DC can be used to charge batteries or to split water to 

produce hydrogen (electrolysis of water). 

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

peak-power shaving, and intermediate daytime load. With energy storage, PV can provide dispatchable 

electricity and/or produce hydrogen. 

• Almost all locations in the United States and worldwide have enough sunlight for cost-effective 

PV. For example, U.S. sunlight in the contiguous states 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 (for example, on roofs or above parking lots), a PV-generating 

station 140 km by 140 km sited at a high solar insolation location in the United States (such as the 

desert Southwest) 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). 

Representative Technologies 

• Wafers of single-crystal or polycrystalline silicon – best cells: 25% efficiency; commercial 

modules: 12%-17%. Silicon modules dominate the PV market and currently cost about $2/Wp to 

manufacture. 

• Thin-film semiconductors (e.g., amorphous silicon, copper indium diselenide, cadmium telluride, 

and dye-sensitized cells) – best cells: 12%-19%; commercial modules: 6%-11%. A new generation of 

thin-film PV modules is going through the high-risk transition to first-time and large-scale 

manufacturing. If successful, market share could increase rapidly. 

• High-efficiency, single-crystal silicon and multijunction gallium-arsenide-alloy cells for 

concentrators – best cells: 27%-39% efficient; precommercial modules: 15%-24%; prototype systems 

are being tested in high solar areas in the southwest United States. 

• Grid-connected PV systems currently sell for about $6-$7/Wp (17¢-22¢/kWh), including support 

structures, power conditioning, and land. 

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 

23
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 1 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. 

• 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 

• Because of public/private partnerships, such as the Thin-Film Partnership with its national research 

teams, U.S. PV technology leads the world in measurable results such as record efficiencies for cells 

and modules. Another partnership, the PV Advanced Manufacturing R&D program, has resulted in 

industry cost reductions of more than 60% and facilitated a sixteen-fold increase of manufacturing 

capacity during the past 12 years. 

• A new generation of potentially lower-cost technologies (thin films) is entering the marketplace. A 

30-megawatt amorphous silicon thin-film plant by United Solar reached full production in 2005. Two 

plants (First Solar and Shell Solar) using even newer thin films (cadmium telluride and copper indium 

diselenide alloys) are in first-time manufacturing at the MW-scale. Thin-film PV has been a focus of 

the federal R&D efforts of the past decade, because it holds promise for module cost reductions. 

• During the past two years, record sunlight-to-electricity conversion efficiencies for solar cells were 

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

(19%-efficient cells and 13%-efficient modules) and cadmium telluride (16%-efficient cells and 11%­

efficient modules). Cell and module efficiencies for these technologies have increased more than 50% 

in the past decade. 

• A unique multijunction (III-V materials alloy) cell was spun off to the space power industry, 

leading to a record cell efficiency (35%) and an R&D 100 Award in 2001. This device configuration is 

expected to dominate future space power for commercial and military satellites. Recent champion cell 

efficiency has reached 39% under concentrated sunlight. DOE is interested in this technology (III-V 

multijunctions), as an insertion candidate for high efficiency terrestrial PV concentrator systems. 

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% efficiency. As a result, selenium 

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

24
• 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, increasing 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. 

Technology Future 

The levelized cost of electricity (in constant 2003$/kWh) for PV are projected to be: 

2003 2007 2020 2025 

Utility-owned Residential 0.25-0.40 0.22 0.8-0.10 NA 

(crystalline Si) 

Concentrator 0.40 0.20 NA 0.04-0.06 

Source: Solar Energy Technologies Program Multiyear Technical Plan, NREL Report No. MP-520­

33875; DOE/GO-102004-1775. 

• Worldwide, approximately 1,200 MW of PV were sold in 2004, with systems valued at more than 

$7 billion; total installed PV is more than 2 GW. The U.S. world market share fell to about 12% in 

2004. 

• Worldwide, market growth for PV has averaged more than 20%/year for the past decade as a result 

of reduced prices and successful global marketing. Worldwide sales grew 36% in 2001, 44% in 2002, 

33% in 2003, and 60% in 2004. 

• Hundreds of applications are cost-effective for off-grid needs. However, the fastest-growing 

segment of the market is battery-free, grid-connected PV, such as roof-mounted arrays on homes and 

commercial buildings in the United States. California is subsidizing PV systems to reduce their 

dependence on natural gas, especially for peak daytime loads that match PV output, such as airconditioning. 

Market Context 

• Electricity for remote locations, especially for billions of people worldwide who do not have 

electricity. 

• U.S. markets include retail electricity for residential and commercial buildings; distributed utility 

systems for grid support, peak-shaving, and other daytime uses (e.g., remote water pumping). 

• Future electricity and hydrogen storage for dispatchable electricity, electric car-charging stations, 

and hydrogen production for portable fuel. 

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

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

September 2005). 

25
Photovoltaics 

Market Data 

PV Cell/Module Production Source: PV News, Vol. 15, No. 2, Feb. 1996; Vol. 16, No. 2, Feb. 1997; Vol. 20, No. 2, Feb(Shipments) 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 Source: Strategies Unlimited(Shipments retained, MW)*

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). 

26
Cumulative Capacity Source: Strategies Unlimited

(Shipments retained, MW)*

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 2004, DOE/EIA-0384(2004) (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 1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 Total 5.8 13.8 31.1 35.5 46.4 50.6 76.8 88.2 97.7 112.1 

Imports 0.3 1.4 1.3 1.9 1.9 1.9 4.8 8.8 10.2 7.3 Exports 1.7 7.5 19.9 22.4 33.8 35.5 55.6 68.4 61.4 66.8 

Domestic Total On-Grid* 0.4 0.2 1.7 1.8 2.2 4.2 6.9 4.9 10.1 13.7 Domestic Total Off-Grid* 3.7 6.1 9.5 11.2 10.3 10.8 14.4 15.0 26.2 31.6 Cumulative Shipments 1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 (since 1982) Total 35.2 84.7 193.3 228.8 275.2 325.7 402.5 490.7 588.4 700.5 

Imports 1.0 5.6 14.3 16.2 18 19.9 24.7 33.5 43.7 51.0 

Exports 5.7 32.9 104 126.5 160.3 195.8 251.3 319.7 381.0 447.8 

Domestic Total On-Grid* 2.9 4.7 8.2 10.0 12.2 16.5 23.3 28.2 38.3 52.0 Domestic Total Off-Grid* 26.6 47.2 81.1 92.3 102.7 113.5 127.9 142.8 169.0 200.6 * Domestic Totals include imports and exclude exports. Electricity generation only, excludes water pumping, communicatitransportation, consumer goods, health, and original equipment manufacturers. 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 

27
Annual U.S. Installations Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United S

(MW) by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, Table 1. http://ww

services.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 1.5 2.0 2.0 2.2 3.7 5.5 12.0 

Distributed 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 4.0 4.4 4.8 5.2 6.5 7.5 9.0 

Industrial/Commercial 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. Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United S

Installations* (MW) 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 Source: Renewable Energy World, July-August 2003, Volume 6, Number 4. (MW) 

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., Comm. 1 7 27 36 60 120 199 

Central Station (>100kW) 1 2 2 2 5 5 

Total 48 89 127 153 201 288 395 

28

2 
Annual U.S. Shipments by Source: PV News, Vol. 15, No. 2, Feb. 1996; Vol. 16, No. 2, Feb. 1997; Vol. 17, No. 2, Feb

Cell Type (MW) No. 2, Feb. 1999; Vol. 19, No. 3, March 2000; Vol. 20, No. 3, March 2001; Vol. 21, No. 3, Ma

22, 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 9.0 10.3 14.0 14.7 16.0 17.0 20.6 ribbon) Amorphous Silicon 1.3 1.1 2.5 3.8 5.3 6.5 7.3 Crystal Silicon 0.3 0.7 0.7 0.2 0.5 0.5 0.5 Concentrators 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 

SI on Low-Cost-Sub 0.1 0.3 0.5 1.0 2.0 2.0 1.7 A-SI on Cz Slice 0 0 Total 34.8 39.9 53.5 53.7 64.6 75 100.6 Annual World Shipments Source: PV News, Vol. 15, No. 2, Feb. 1996; Vol. 16, No. 2, Feb. 1997; Vol. 17, No. 2, Febby Cell Type (MW) No. 2, Feb. 1999; Vol. 19, No. 3, March 2000; Vol. 20, No. 3, March 2001; Vol. 21, No. 3, Ma

22, No. 5, May 2003; and Renewable Energy World, July-August 2003, Volume 6, Number 4

1980 1985 1990 1995 1996 1997 1998 0 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 0.3 0.7 0.2 0.2 0.5 0.5 0.5 Concentrators 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 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 

29

3.7 
Annual U.S. Shipments by Source: EIA, Solar Collector Manufacturing Activity annual reports, 1982-1992; and EIA, Re

Cell Type (MW) Annual 1997, Table 27; REA 2000, Table 26; REA 2002, Table 28; REA 2003, Table 28. 

1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 

Single-Crystal Silicon 19.9 21.7 30 30.8 47.2 51.9 54.7 74.7 

Cast and Ribbon 

9.9 12.3 14.3 16.4 26.2 33.2 29.9 29.4 

Crystalline Silicon Crystalline Silicon Total 5.5 12.5 29.8 34 44.3 47.2 73.5 85.2 84.7 104.1 

Thin-Film Silicon 0.3 1.3 1.3 1.4 1.9 3.3 3.3 2.7 12.5 7.4 

Concentrator Silicon 0.1 0.2 0.2 0.1 0.1 0.3 0.5 0.6 

Other Total 5.8 13.8 31.2 35.6 46.3 50.6 76.8 88.2 97.7 112.1 Annual Grid-Connected Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United SCapacity (MW) by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, derived from Tab

http://www.oja-services.nl/iea-pvps/nsr02/usa2.htm. Japan data from PV News, Vol. 23, No. 

2004. 

1995 1996 1997 1998 1999 2000 2001 

U.S. 1.3 2.7 2.2 5.2 7.0 12.5 

Japan 3.9 7.5 19.5 24.1 57.7 74.4 91.0 Note: Japan data not necessarily grid-connected Cumulative Grid- Source: The 2002 National Survey Report of Photovoltaic Power Applications in the United SConnected Capacity (MW) by Paul D. Maycock and Ward Bower, May 31, 2003, prepared for the IEA, derived from Tab

http://www.oja-services.nl/iea-pvps/nsr02/usa2.htm. Japan data from PV News, Vol. 23, No. 

2004. 

1995 1996 1997 1998 1999 2000 2001 

U.S. 21.7 23.0 25.7 27.9 33.1 40.1 52.6 Japan 5.8 13.3 32.8 56.9 114.6 189.0 280.0 

Japan Grid-Connected Source: IEA Photovoltaic Power Systems Program, National Survey Report of PV Power Ap

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

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 

30
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. 

31
Technology Performance 

Efficiency 

Cell (%) 

Source: Solar Energy Technologies Program Multiyear Technical Plan, NREL Report No. DOE/GO-102004-1775. 

2003 2007 2020 2025 

Crystalline Silicon NA NA NA NA 

Concentrator 25 33 NA 40 

Module (%) Crystalline Silicon  Concentrator 

14 

NA 

15 

NA 

15-20 

NA 

NA 

NA 

System (%) Crystalline Silicon 

Concentrator 

11.5 

15 

14 

22 

16 

NA 

NA 

33 

Cost 

Module ($/Wp) 

($/m 

2) 

BOS ($/Wp) 

Crystalline Silicon 

 Concentrator 

Crystalline Silicon 

 Concentrator 

2003 

4.80 

160 

0.85 

0.60 

2007 

2.50 

90 

0.60 

0.30 

2020 

1.00-1.50 

NA 

0.40 

NA 

2025 

NA 

80 

NA 

0.15 

Total Installed System ($/Wp) Crystalline Silicon *  Concentrator 

6.20-9.50 

NA 

5.20 

NA 

2.30-2.80 

NA 

NA 

NA 

O&M ($/kWh) Crystalline Silicon  Concentrator 

0.08 

0.02 

.0.02 

0.01 

0.005 

NA 

NA 

0.005 

32
Wind Energy
 

Technology Description 

Wind turbine technology converts the kinetic energy in wind to electricity. Grid-connected wind power 

reduces greenhouse gas 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 in developing countries. 

System Concepts 

• Most modern wind turbines operate using aerodynamic lift 

generated by airfoil-type blades, yielding much higher efficiency 

than traditional windmills that relied on wind “pushing” the 

blades. Lifting forces spin the blades, driving a generator that 

produces electric power in proportion to wind speed. Turbines 

either rotate at constant speed and directly link to the grid, or at 

variable speed for better performance, using a power electronics 

system for grid connection. Utility-scale turbines for wind plants 

range in size up to several megawatts, and smaller turbines (under 

100 kilowatts) serve a range of distributed, remote, and standalone power applications. 

Representative Technologies 

• The most common machine configuration is a three-bladed wind turbine, which operates “upwind” 

of the tower, with the blades facing into the wind. To improve the cost-effectiveness of wind turbines, 

technology advances are being made for rotors and controls, drive trains, towers, manufacturing 

methods, site-tailored designs, and offshore and onshore foundations. 

Technology Applications 

• In the United States, the wind energy capacity exploded from 1,600 MW in 1994 to more than 

9,200 MW by the end of 2005 – enough to serve more than 2.5 million households. 

• Current performance is characterized by levelized costs of 3¢-5¢/kWh (depending on resource 

quality and financing terms), capacity factors of 30%-50%, availability of 95-98%, total installed costs 

of approximately $1,000-$1,300/kW, and efficiencies of 65%-75% of theoretical (Betz limit) 

maximum. 

Current Status 

• In 1989, the wind program set a goal of 5¢/kWh by 1995 and 4¢/kWh by 2000 for sites with 

average wind speeds of 16 mph. The program and the wind industry met the goals as part of dramatic 

cost reductions from 25¢-50¢/kWh in the early 1980s to 4¢-6¢/kWh today (2005). 

• Wind power is the world’s fastest-growing energy source. In the past decade, the global wind 

energy capacity has increased tenfold from 3,500 MW in 1994 to almost 50,000 MW by the end of 

2004. During 2004, nearly 8,000 MW of new capacity was added worldwide. 

• 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 throughout the 

country. 

• The National Wind Technology Center (operated by the National Renewable Energy Laboratory in 

Golden, Colorado) is recognized as a world-class center for wind energy R&D and has many facilities 

– such as blade structural test stands and a large gearbox test stand – not otherwise available to the 

domestic industry. 

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. 

33
• 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. 

• In 2004, Clipper Windpower began testing on its highly innovative, multiple-drive 2.5 MW Liberty 

prototype wind turbine. 

• In 2005, the U.S. wind energy industry had a record-breaking year for new installations, adding 

more than 2,400 MW of new capacity to the nation’s electric grid. 

• In 2006, the U.S. Department of Energy signed a $27 million contract with General Electric to 

develop a multimegawatt offshore wind power system; and Clipper Windpower begins manufacturing 

its multiple-drive, 2.5 MW turbine. 

Technology Future 

The levelized cost of electricity (2002 $/MWh) for wind energy technology is projected to be: 

2005 2010 2020 2030 2040 2050 

Class 4 5.5 4.0 3.1 2.9 2.9 2.8 

Class 6 4.1 3.0 2.6 2.5 2.4 2.3 

Source: Projected Benefits of Federal Energy Efficiency and Renewable Energy Programs – FY 2006 

Budget Request, NREL/TP-620-37931, May 2005. 

• Installed wind capacity in the United States expanded from 2,554 MW to 4,150 MW during the 

period of 2000 to 2005, but still make up less than 1% of total U.S. generation. 

• California has the greatest installed wind capacity, followed by Texas, Iowa, Minnesota, Oregon, 

Washington, Wyoming, New Mexico, Colorado, and Oklahoma. 

• Wind technology is competitive today in bulk power markets at Class 5 and 6 wind sites, with 

support from the production tax credit – and in high-value niche applications or markets that recognize 

non-cost attributes. Its competitiveness is negatively affected by policies regarding ancillary services 

and transmission and distribution regulations. 

• Continued cost reductions from low wind-speed technologies will increase the resource areas 

available for wind development by 20-fold and move wind generation five times closer to major load 

centers. 

• Wind energy is often the least variable cost source of generation in grid supplied electricity and due 

to its less predictable (variable resource) supply; wind usually displaces natural gas and coal generated 

electricity as these sources adjust to hourly changes in demand and supply. Emerging markets for wind 

energy include providing energy for water purification, irrigation, and hydrogen production. 

34
• 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, leaving wind power at a disadvantage. 

• In the United States, the wind industry is thinly capitalized, except for General Electric Wind 

Energy, which recently acquired wind technology and manufacturing assets in April 2002. About six 

manufacturers and six to 10 developers characterize the U.S. industry. 

• In Europe, there are about 10 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. 

• 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. Because the wind resource is variable, 

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 onshore wind turbines. However, offshore resources are located close to major load 

centers. 

• Small wind turbines (100 kW and smaller) for distributed and residential grid-connected 

applications are being used to harness the nation’s abundant wind resources and defer impacts to the 

long-distance transmission market. Key market drivers include state renewable portfolio standards, 

incentive programs, and demand for community-owned wind applications. 

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

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

September 2005). 

35
Wind 

Market Data 

Grid-Connected Wind Source: Reference IEA (data supplemented by Windpower Monthly, April 2001), 2001 data f

Capacity (MW) 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 

0 0 6 193 264 324 331 344 

UK 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 Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 2003. (MW) 

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. 

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% 

36
State-Installed Capacity Source: American Wind Energy Association and Global Energy Concepts. 

Annual State-Installed Capacity (MW) Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 2

 California* N/A N/A 3.0 0.0 8.4 0.7 250.0 0.0 67.1 108.0 20

 Texas 0 0 41.0 0.0 0.0 0.0 139.2 0.0 915.2 0.0 20

 Minnesota 0 0 0.0 0.0 0.2 109.2 137.6 17.8 28.6 17.9 23 Iowa 0 0 0.1 0.0 1.2 3.1 237.5 0.0 81.8 98.5 4

Wyoming 0 0 0.0 0.1 0.0 1.2 71.3 18.1 50.0 0.0 14

 Oregon 0 0 0.0 0.0 0.0 25.1 0.0 0.0 131.8 64.8 4

Washington 0 0 0.0 0.0 0.0 0.0 0.0 0.0 176.9 48.0 1

 Colorado 0 0 0.0 0.0 0.0 0.0 21.6 0.0 39.6 0.0 16

 New Mexico 0 0 0.0 0.0 0.0 0.0 1.3 0.0 0.0 0.0 20

 Oklahoma 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 17 Total of 10 States N/A N/A 44.1 0.1 9.8 139.3 858.5 35.9 1491.0 337.2 144

Total U.S. N/A N/A 44.0 1.0 16.0 142.0 884.0 67.0 1694.0 449.7 169

Top 10 States 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 2 California* N/A N/A 1,387.0 1,387.0 1,396.0 1,396.0 1,646.0 1,646.0 1,714.0 1,822.0 2,04

 Texas 0 0 41.0 41.0 41.0 41.0 180.2 180.2 1,095.5 1,095.5 1,29

 Minnesota 0 0 25.7 25.7 25.9 135.1 272.7 290.5 319.1 335.9 56 Iowa 0 0 0.7 0.8 2.0 5.0 242.5 242.5 324.2 422.7 47

Wyoming 0 0 0.0 0.1 0.1 1.3 72.5 90.6 140.6 140.6 28

 Oregon 0 0 0.0 0.0 0.0 25.1 25.1 25.1 157.5 218.4 25

Washington 0 0 0.0 0.0 0.0 0.0 0.0 0.0 178.2 228.2 24

 Colorado 0 0 0.0 0.0 0.0 0.0 21.6 21.6 61.2 61.2 22

 New Mexico 0 0 0.0 0.0 0.0 0.0 1.3 1.3 1.3 1.3 20

 Oklahoma 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 17

 Total of 10 states N/A N/A 1,454.4 1,454.6 1,465.0 1,603.5 2,461.9 2,497.8 3,991.6 4,325.8 5,76Total U.S. 10.0 1039.0 1525.0 1,697.0 1,698.0 1,706.0 1,848.0 2,511.0 2,578.0 4,275.0 4,686.0 6,35

0 * 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 later. 

37
Cumulative Installed Source: U.S. - EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., Au

Capacity (MW) IEA R&D Wind Countries - IEA Wind Energy Annual Reports, 1995-2003. IEA Total - "Renewa

IEA, 2002. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. 17.5 1,799 1,731 1,678 1,610 1,720 2,252 2,377 3,864 

IEA R&D Wind Countries2 10,040 15,440 21,553 

IEA Total N/A 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 continfacilities. 2. Data for IEA R&D Wind Countries through 2001 included 16 IEA countries. Ireland and Switzerland were added in 2002 and 2003. 

Annual Generation from Source: U.S. - EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., AuCumulative Installed IEA R&D Wind Countries - IEA Wind Energy Annual Reports, 1995-2003. IEA Total - "RenewaCapacity (Billion kWh) IEA, 2002. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. N/A 0.006 2.8 3.2 3.2 3.3 3.0 4.5 5.6 6.7 IEA R&D Wind Countries2 7.1 8.4 10.9 11.3 22.0 26.4 37.2 

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 Switzerland Portugal was added in 2003. Annual Wind Energy Consumption for Electric Generation (Trillion Btu) 

Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2003) (Washington, D.C., Septemb

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. Total (s)=Less than 0.5 trillion Btu. 

N/A (s) 29.0 32.6 33.4 33.6 30.9 45.9 57.1 68.4 

38
Technology Performance 

Source: Projected Benefits of Federal Energy Efficiency and Renewable En

Energy Production 2006 Budget Request, NREL/TP-620-37931, May 2005. 

2005 2010 2015 2020 2025 2030 2035 

Capacity Factor (%) Class 4 33.8 40.4 46.3 46.9 47.2 48.0 48.2  Class 6 43.6 49.5 50.7 51.4 51.7 51.9 52.1 

Source: Projected Benefits of Federal Energy Efficiency and Renewable En

Cost 2006 Budget Request, NREL/TP-620-37931, May 2005. (2002 dollars) 

Capital Cost ($/kW) Class 4 

Class 6 

2005 

1103 

1050 

2010 

982 

893 

2015 

919 

840 

2020 

893 

819 

2025 

866 

814 

2030 

866 

788 

2035 

861 

777 

O&M ($/kW) Onshore 25.0 20.0 16.0 15.0 14.2 13.8 13.5 

Levelized Cost of Energy* ($/kWh) (2002 dollars) 

Source: Projected Benefits of Federal Energy Efficiency a 2006 Budget Request, NREL/TP-620-37931, May 2005. 

2005 2010 2015 2020 2025 

Class 4 55.1 40.3 32.3 30.8 29.6 Class 6 40.9 30.3 27.2 26.1 25.6 

nd Rene 

2030 

29.0 24.7 

2035 

28.7 24.3 

wable En 

39
 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 a 

clean 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 

this 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 particulate matter, no carbon dioxide, and no pollution. 

System Concepts 

• Hydrogen 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. 

Hydrogen storage 

• Pressurized gas and cryogenic liquid (commercial today) 

40
• 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. 

• 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. 

Polymer electrolyte membrane (PEM) fuel cell - The polymer electrolyte 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. 

41
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. 

• 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 electrolyzer systems are 55-75% 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. Direct conversion of sunlight 

to hydrogen using a semiconductor-based photoelectrochemical cell was recently demonstrated at 

12.4% efficiency. 

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 bus and energy companies have been undertaken. 

Small-scale power systems using fuel cells fuel cells have been introduced to the power generation 

market, but subsidies are required to be economically competitive. Small fuel cells for battery 

replacement applications have been developed. The United States is conducting a major five-year 

learning demonstration of fuel cell vehicles and hydrogen infrastructure. Four teams comprised of 

automobile manufacturers and energy companies are conducting the study. 

• Major industrial companies are pursuing R&D in fuel cells and hydrogen production technologies 

with a mid-term time frame for deployment for both stationary and vehicular applications. 

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 

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. 

42
- 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—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 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 ($2-3/gallon in 2001 dollars). 

• For a fully developed hydrogen energy system, a new hydrogen infrastructure/delivery system will 

be required. 

• 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. 

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

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

September 2005); and National Renewable Energy Laboratory. Gas-Fired Distributed Energy Resource 

Technology Characterizations. NREL/TP-620/34783. November 2003. 

43
Advanced Hydropower
 

Technology Description 

Hydroelectric power generates no 

greenhouse gas. To the extent that 

existing hydropower can be maintained 

or expanded through advances in 

technology, it can continue to be an 

important part of a greenhouse gas 

emissions-free energy portfolio. 

Advanced hydropower is technology 

that produces hydroelectricity both 

efficiently and with improved 

environmental performance. 

Traditional hydropower may have 

environmental effects, such as fish 

mortality and changes to downstream 

water quality and quantity. The goal of 

advanced hydropower is to maximize the use of water for generation while improving environmental 

performance. 

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, or canals, or water released from upstream storage reservoirs. 

• New environmental and biological criteria for turbine design and operation are being developed to 

help sustain hydropower’s role as a clean, renewable energy source – and to enable upgrades of 

existing facilities and retrofits at existing dams. 

Representative Technologies 

• New turbine designs that improve survivability of fish that pass through the power plant. 

• Autoventing turbines to increase dissolved oxygen in discharges downstream of dams. 

• Re-regulating 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 

and to optimize operation of reservoir systems. 

• Advanced instrumentation and control systems that modify turbine operation to maximize 

environmental benefits and energy production. 

Technology Applications 

• Hydropower provides about 78,000 MW of the nation’s electrical-generating capability. This is 

about 80 percent of the electricity generated from renewable energy sources. 

• Existing hydropower generation faces a combination of real and perceived environmental effects, 

competing uses of water, regulatory pressures, and changes in energy economics (deregulation, etc.); 

potential hydropower resources are not being developed for similar reasons. 

• Some new environmentally friendly technologies such as low head and low impact hydroelectric 

are being implemented in part stimulated by green power programs. 

• DOE's Advanced Hydropower Turbine System (AHTS) program will be completing public-private 

partnerships with industry to demonstrate the feasibility of new turbine designs (e.g., aerating turbines 

at the Osage Dam, and a Minimum Gap Runner turbine at the Wanapum Dam). 

44
Current Status 

• TVA has demonstrated that improved turbine designs, equipment upgrades, and systems 

optimization can lead to significant economic and environmental benefits – energy production was 

increased approximately 12% while downstream fish resources were significantly improved. 

• Field-testing of the Kaplan turbine Minimum Gap Runner design indicates that fish survival can be 

significantly increased, if conventional turbines are modified. The full complement of Minimum Gap 

Runner design features will be tested at the Wanapum Dam in FY 2005. 

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, it 

increased to 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 

• Voith Siemens Hydro Power and the TVA have established a partnership to market 

environmentally friendly technology at hydropower facilities. Their products were developed partly by 

funding provided by DOE and the Corps of Engineers, as well as private sources. 

• In a competitive solicitation, DOE accepted proposals for advanced turbine designs from Voith 

Siemens, Alstom, American Hydro, and General Electric Co. Field verification and testing is underway 

with some of these designs to demonstrate improved environmental performance. 

• Flash Technology is developing strobe lighting systems to force fish away from hydropower 

intakes and to avoid entrainment mortality in turbines. Implementation at more sites may allow 

improved environmental performance with reduced spillage. 

Market Context 

• Advanced hydropower products can be applied at more than 80% of existing hydropower projects 

(installed conventional capacity is now 94 GW); the potential market also includes 15-20 GW at 

existing dams (i.e. no new dams required for development) and more than 30 GW of undeveloped 

hydropower. 

• Retrofitting advanced technology and optimizing system operations at existing facilities would lead 

to at least a 6% increase in energy output – if fully implemented, this would equate to 5 GW and 

18,600 GWh of new, clean energy production. 

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

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

September 2005). 

45
Hydroelectric Power 

Market Data 

U.S. Installed Capacity (MW)* Source: Renewable Electric Plant Information System (REPiS), Version 7, NREL, 2003. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 200

Annual 1,391 3,237 862 1,054 19.9 64.0 7.6 179.3 1.1 1

Cumulative 80,491 87,839 90,955 94,052 94,072 94,136 94,143 94,323 94,324 94,33

* There are an additional 21 MW of hydroelectric capacity that are not accounted for here because they have no specific online da2003 data not complete as REPiS database is updated through 2002. 

Cumulative Grid- Source: U.S. data from EIA, AER 2004, Table 8.11a; World Total from EIA, International Energy Annual, 19

Connected Hydro International data from International Energy Agency, Electricity Information 2004. Capacity (MW)1 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

U.S. Conventional and other Hydro 81,700 88,900 73,923 78,562 76,437 79,415 79,151 79,393 79,359 79,484 Pumped Storage2 N/A N/A 19,462 21,387 21,110 19,310 19,518 19,565 19,522 19,096 

U.S. Hydro Total 81,700 88,900 93,385 99,948 97,548 98,725 98,669 98,958 98,881 98,580 OECD Europe3 124,184 124,577 130,886 132,893 134,902 135,939 133,307 136,251 140,779 141,913 

IEA Europe4 123,960 124,357 130,663 132,666 134,038 135,074 132,315 135,254 138,093 138,912 

Japan 21,377 19,980 20,825 21,171 21,222 21,277 21,477 21,555 22,019 22,081 

OECD Total 286,969 300,725 316,291 340,259 342,893 346,342 342,673 346,446 351,513 352,564 

IEA Total 286,745 300,505 316,068 330,703 331,947 335,395 331,930 335,768 339,145 339,880 

World Total 470,669 537,734 600,206 650,936 661,237 673,797 680,610 697,749 712,689 723,581 

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 after included only after the year they joined. 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 

46
Annual Generation from Source: EIA, International Energy Annual 2003, DOE/EIA-0219(02), Table 1.5. 

Cumulative Installed Capacity 

(Billion kWh)

1980 1985 1990 1995 1996 1997 1998 1999 2000 

United States 279 284 289 308 344 352 319 313 270 Canada 251 301 294 332 352 347 329 342 355 

Mexico 17 26 23 27 31 26 24 32 33 

Brazil 177 205 251 263 276 289 290 302 Western Europe 453 453 506 491 506 523 531 555 Former U.S.S.R. 128 205 231 238 215 216 225 227 228 Eastern Europe 432 26 23 34 34 36 35 35 31 

China 184 91 125 184 185 193 203 211 241 

Japan 82 88 81 80 89 92 86 86 Rest of World 27 273 328 435 504 515 522 533 541 558 

58 

World Total 88 1,736 1,973 2,167 2,466 2,511 2,564 2,571 2,609 2,658 2State Generating Capability* Source: EIA, Electric Power Annual 2004 – Spreadsheets, “1990 - 2002 Existing Nameplate and (MW) Capacity by Energy Source and Producer Type (EIA-860)” 

http://www.eia.doe.gov/cneaf/electricity/epa/existing_capacity_state.xls 

Top 10 States 1990 1995 1996 1997 1998 1999 2000 2001 2002 Washington 19,935 20,487 20,431 20,923 21,012 21,011 21,011 21,006 21,016 

California 12,687 13,519 13,500 13,475 13,383 13,445 13,475 13,471 13,523 

Oregon 8,221 8,268 8,267 8,264 8,265 8,249 8,261 8,240 8,211 

New York 5,345 5,545 5,557 5,565 5,668 5,662 5,659 5,712 5,804 

Tennessee 3,717 3,818 3,818 3,937 3,950 3,950 3,950 3,948 3,948 

Georgia 2,453 3,287 3,005 3,305 3,314 3,314 3,313 3,313 3,613 

South Carolina 2,367 3,468 3,468 3,442 3,442 3,452 3,455 3,453 3,453 

Virginia 3,072 3,126 3,149 3,082 3,093 3,090 3,091 3,088 3,088 

Alabama 2,857 2,868 2,864 2,904 2,961 2,961 2,961 2,959 2,959 

Arizona 2,685 2,885 2,885 2,893 2,893 2,890 2,890 2,890 2,893 

U.S. Total 89,828 94,513 94,372 95,222 95,496 95,802 95,879 95,844 96,343 

* Values are nameplate capacity for total electric industry 

47
State Annual Generation from Source: EIA, Electric Power Annual 2002 – Spreadsheets, “1990 - 2002 Net Generation by Stat

Cumulative Installed Capacity* Producer by Energy Source (EIA-906)” http://www.eia.doe.gov/cneaf/electricity/epa/generation_(Billion kWh) Top 10 States 1990 1995 1996 1997 1998 1999 2000 2001 2002 Washington 87.5 82.5 98.5 104.2 79.8 97.0 80.3 54.7 78.2 Oregon 41.2 40.8 44.9 46.7 39.9 45.6 38.1 28.6 34.4 California 24.8 50.5 46.9 42.1 50.8 40.4 39.3 25.2 30.9 New York 27.1 24.8 27.8 29.5 28.2 23.6 23.9 22.2 24.1 Montana 10.7 10.7 13.8 13.4 11.1 13.8 9.6 6.6 9.6 

Alabama 10.4 9.5 11.1 11.5 10.6 7.8 5.8 8.4 8.8 Idaho 9.1 11.0 13.3 14.7 12.9 13.5 11.0 7.2 8.8 Arizona 7.7 8.5 9.5 12.4 11.2 10.1 8.6 7.9 7.6 Tennessee 9.5 9.0 10.8 10.4 10.2 7.2 5.7 6.2 7.3 South Dakota 3.9 6.0 8.0 9.0 5.8 6.7 5.7 3.4 4.4 U.S. Total 289.4 308.1 344.1 352.4 318.9 313.4 270.0 208.1 255.6 * Values are for total electric industry. Years before 1998 do not include nonutility generation. 

Annual Hydroelectric Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005) T

Consumption for ElectricGeneration (Trillion Btu)

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 

U.S. Total 2,900 2,970 3,046 3,205 3,590 3,640 3,297 3,268 2,811 2,201 2,689 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 electric utilitie

independent power producers, commercial plants, and industrial plants. 

48
Building Technologies
 

Technology Description 

Building equipment 

Energy use in buildings depends on equipment to 

transform fuel or electricity into end-use services 

such as delivered heat or cooling, light, fresh air, 

vertical transport, cleaning of clothes or dishes, and 

information processing. There are energy-saving 

opportunities within individual pieces of equipment 

– as well as at the system level – through proper 

sizing, reduced distribution and standby losses, heat 

recovery and storage, and optimal control. 

Building envelope 

The building envelope is the interface between the 

interior of a building and the outdoor environment. 

In most buildings, the envelope – along with the 

outdoor weather – is the primary determinant of the amount of energy used to heat, cool, and ventilate. 

A more energy-efficient envelope means lower energy use in a building and lower greenhouse gas 

emissions. The envelope concept can be extended to that of the “building fabric,” which includes the 

interior partitions, ceilings, and floors. Interior elements and surfaces can be used to store, release, 

control, and distribute energy, thereby further increasing the overall efficiency of the buildings. 

Whole building integration 

Whole building integration uses data from design (together with sensed data) to automatically 

configure controls and commission (i.e., start-up and check out) and operate buildings. Control systems 

use advanced, robust techniques and are based on smaller, less expensive, and much more abundant 

sensors. These data ensure optimal building performance by enabling control of building systems in an 

integrated manner and continuously recommissioning them using automated tools that detect and 

diagnose performance anomalies and degradation. Whole building integration systems optimize 

operation across building systems, inform and implement energy purchasing, guide maintenance 

activities, document and report building performance, and optimally coordinate on-site energy 

generation with building energy demand and the electric power grid, while ensuring that occupant 

needs for comfort, health, and safety were met at the lowest possible cost. 

System Concepts 

Building equipment 

• Major categories of end-use equipment include heating, cooling, and hot water; ventilation and 

thermal distribution; lighting; home appliances; miscellaneous (process equipment and consumer 

products); and on-site energy and power. 

• Key components vary by type of equipment, but some crosscutting opportunities for efficiency 

include improved materials, efficient low-emissions combustion and heat transfer, advanced 

refrigerants and cycles, electrodeless and solid-state lighting, smart sensors and controls, improved 

small-power supplies, variable-capacity systems, reduction of thermal and electrical standby losses, 

cogeneration based on modular fuel cells and microturbines, and utilization of waste heat from fuel 

cells and microturbines. 

Building envelope 

• Control of envelope characteristics provides control over the flow of heat, air, moisture, and light 

into the building. These flows and the interior energy and environmental loads determine the size and 

energy use of HVAC and distribution systems. 

49
• Materials for exterior walls, roofs, foundations, windows, doors, interior partition walls, ceilings, 

and floors that can impact future energy use include insulation with innovative formula foams and 

vacuum panels; optical control coatings for windows and roofs; and thermal storage materials, 

including lightweight heat-storage systems. 

Whole building integration 

• The system consists of design tools, automated diagnostics, interoperable control-system 

components, abundant wireless sensors and controls, and highly integrated operation of energy-using 

and producing systems. 

• These components would work together to collect data, configure controls, monitor operations, 

optimize control, and correct out-of-range conditions that contribute to poor building performance. 

Whole building integration would ensure that essential information – especially the design intent and 

construction implementation data – would be preserved and shared across many applications 

throughout the lifetime of the building. 

• Equipment and system performance records would be stored as part of a networked building 

performance knowledge base, which would grow over time and provide feedback to designers, 

equipment manufacturers, and building operators and owners. 

• Optimally integrate on-site power production with building energy needs and the electric-power 

grid by applying intelligent control to building cooling, heating, and power. 

Representative Technologies 

Building equipment 

• Residential gas-fired absorption heat pumps, centrifugal chillers, desiccant preconditioners for 

treating ventilation air, heat-pump water heaters, proton exchange membrane fuel cells, heat pump 

water heaters, solid-state lighting, and lighting controls. 

• Specialized HVAC (heating, ventilating, and air-conditioning) systems for research laboratories, 

server/data systems, and other buildings housing high-technology processes. 

Building envelope 

• Superinsulation: Vacuum powder-filled, gas-filled, and vacuum fiber-filled panels; structurally 

reinforced beaded vacuum panels; and switchable evacuated panels with insulating values more than 

four times those of the best currently available materials should soon be available for niche markets. 

High-thermal-resistant foam insulations with acceptable ozone depletion and global warming 

characteristics should allow for continued use of this highly desirable thermal insulation. 

• Advanced window systems: Krypton-filled, triple-glazed, low-E windows; electrochromic glazing; 

and hybrid electrochromic/photovoltaic films and coatings should provide improved lighting and 

thermal control of fenestration systems. Advanced techniques for integration, control, and distribution 

of daylight should significantly reduce the need for electric lighting in buildings. Self-drying wall and 

roof designs should allow for improved insulation levels and increase the lifetimes for these 

components. More durable high-reflectance coatings should allow better control of solar heat on 

building surfaces. 

• Advanced thermal storage materials: Dry phase-change materials and encapsulated materials 

should allow significant load distribution over the full diurnal cycle and significant load reduction 

when used with passive solar systems. 

Whole building integration 

• DOE is developing computer-based building commissioning and operation tools to improve the 

energy efficiency of “existing” buildings. It is also investing in the next generation of buildingsimulation programs that could be integrated into design tools. 

• DOE, in collaboration with industry, also is developing and testing technologies for combined 

cooling, heating, and power; and wireless sensor and control systems for buildings. 

50
Technology Applications 

Building equipment 

• Technology improvements during the past 20 years – through quality engineering, new materials, 

and better controls – have improved efficiencies in lighting and equipment by 15% to 75%, depending 

on the type of equipment. Efficiencies of compact fluorescent lamps are 70% better than incandescent 

lamps; refrigerator energy use has been reduced by more than three-quarters during the past 20 years; 

H-axis clothes washers are 50% more efficient than current minimum standards. Electronic equipment 

has achieved order-of-magnitude efficiency gains, at the microchip level, every two to three years. 

Building envelope 

• Building insulations have progressed from the 2-4 hr oF ft2

/Btu/in. fibrous materials available 

before 1970 to foams reaching 7 hr oF ft2

/Btu/in. Superinsulations of more than 25 oF ft2/Btu/in. will be 

available for niche markets soon. Improvements in window performance have been even more 

spectacular. In the 1970s, window thermal resistance was 1 to 2 oF ft2

/Btu. Now, new windows have 

thermal resistance of up to 6 oF ft2

/Btu (whole window performance). Windows are now widely 

available with selective coatings that reduce infrared transmittance without reducing visible 

transmittance. In addition, variable-transmittance windows under development will allow optimal 

control to minimize heating, cooling, and lighting loads. 

Whole building integration 

• Savings from improved operation and maintenance procedures could save more than 30% of the 

annual energy costs of existing commercial buildings, even in many of those buildings thought to be 

working properly by their owners/operators. These technologies would have very short paybacks, 

because they would ensure that technologies were performing as promised, for a fraction of the cost of 

the installed technology. 

• Savings for new buildings could exceed 70%, using integration of building systems; and, with 

combined cooling, heating and power, buildings could become net electricity producers and distributed 

suppliers to the electric power grid. 

Current Status 

Building equipment 

• Recent DOE-sponsored R&D, often with industry participation, includes an improved airconditioning cycle to reduce oversizing and improve efficiency; a replacement for inefficient, hightemperature halogen up-lights (torchieres), which use only 25% of the power, last longer, and eliminate 

potential fire hazards; ozone-safe refrigerants, where supported R&D was directed toward lubrication 

materials problems associated with novel refrigerants and ground-source heat pumps. 

Building envelope 

• A DOE-sponsored RD&D partnership with the Polyisocyanurate Insulation Manufacturers 

Association, the National Roofing Contractors Association, the Society of the Plastics Industry, and 

Environmental Protection Agency (EPA) helped the industry find a replacement for chloroflurocarbons 

(CFCs) in polyisocyanurate foam insulation. This effort enabled the buildings industry to transition 

from CFC-11 to HCFC-141b by the deadline required by the Montreal protocol. 

• Spectrally selective window glazings – which reduce solar heat gain and lower cooling loads – and 

high-performance insulating materials for demanding thermal applications are available. 

Whole building integration 

• Energy 10 models passive solar systems in buildings. 

• DOE-2: international standard for whole building energy performance simulation has thousands of 

users. DOE released Energy Plus, new standard for building energy simulation and DOE-2 successor. 

• The International Alliance for Interoperability is setting international standards for interoperability 

of computer tools and components for buildings. 

• DOE-BESTEST is the basis for ANSI/ASHRAE Standard 140, Method of Test for the Evaluation 

of Building Energy Simulation Programs. 

51
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, 

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 

52
Technology Future 

Building equipment 

• Building equipment, appliances, and lighting systems currently on the market vary from 20% to 

100% efficient (heat pumps can exceed this level by using “free” energy drawn from the environment). 

This efficiency range is narrower where cost-effective appliance standards have previously eliminated 

the least-efficient models. 

• The stock and energy intensity of homes are growing faster than the building stock itself, as 

manufacturers introduce – and consumers and businesses eagerly accept – new types of equipment, 

more sophisticated and automated technologies, and increased levels of end-use services. 

• The rapid turnover and growth of many types of building equipment – especially electronics for 

computing, control, communications, and entertainment – represent important opportunities to rapidly 

introduce new, efficient technologies and quickly propagate them throughout the stock. 

• The market success of most new equipment and appliance technologies is virtually ensured if the 

efficiency improvement has a 3-year payback or better and amenities are maintained; technologies with 

payback of 4 to 8-plus years also can succeed in the market, provided that they offer other customervalued features (e.g., reliability, longer life, improved comfort or convenience, quiet operation, smaller 

size, lower pollution levels). 

• Applications extend to every segment of the residential and nonresidential sectors. Major 

government, institutional, and corporate buyers represent a special target group for voluntary early 

deployment of the best new technologies. 

• Building equipment and appliances represent an annual market in the United States, alone, of more 

than $200B, involving thousands of large and small companies. Certain technologies, such as office 

and home electronics, compete in global markets with little or no change in performance specifications. 

Building envelope 

• A critical challenge is to ensure that new homes and buildings are constructed with good thermal 

envelopes and windows when the technologies are most cost-effective to implement. 

• The market potential is significant for building owners taking some actions to improve building 

envelopes. Currently, 40% of residences are well insulated, 40% are adequately insulated, and 20% are 

poorly insulated. More than 40% of new window sales are of advanced types (low-E and gas-filled). In 

commercial buildings, more than 17% of all windows are advanced types. More than 70% of 

commercial buildings have roof insulation; somewhat fewer have insulated walls. 

• Building products are mostly commodity products. A number of companies produce them; and 

each has a diverse distribution system, including direct sales, contractors, retailers, and discount stores. 

Another critical challenge is improving the efficiency of retrofits of existing buildings. Retrofitting is 

seldom cost-effective on a stand-alone basis. New materials and techniques are required. 

• Many advanced envelope products are cost-competitive now, and new technologies will become so 

on an ongoing basis. There will be modest cost reductions over time as manufacturers compete. 

• Building structures represent an annual market in the United States of more than $70B/year and 

involve thousands of large and small product manufacturers and a large, diverse distribution system 

that plays a crucial role in product marketing. Exporting is not an important factor in the sales of most 

building structure products. 

Whole building integration 

• The future vision of buildings technologies is one of “net zero energy” buildings which use a 

combination of integrated electricity generation--such as photovoltaics--paired with energy 

efficiency and power controls, to create a building that on average during a year produces 

enough energy for all the energy demands within the building. 

• Design tools for energy efficiency are used by fewer than 2% of the professionals involved in the 

design, construction, and operation of commercial buildings in the United States. A larger fraction of 

commercial buildings have central building-control systems. Few diagnostic tools are available 

commercially beyond those used for air-balancing or integrated into equipment (e.g., Trane Intellipack 

53
____________________________________________________________________________________ 

____________________________________________________________________________________ 

System) and the recently announced air-conditioning diagnostic hand-held service tool by Honeywell 

(i.e. Honeywell HVAC Service Assistant). 

• The Department of Energy – in concert with the California Energy Commission – is testing a 

number of automated diagnostic tools and techniques with commercial building owners, operators, and 

service providers in an effort to promote commercial use. About 12 software vendors develop, support, 

and maintain energy design tools; most are small businesses. Another 15 to 20 building automation and 

control vendors exist in the marketplace – the major players include Johnson Controls, Honeywell, and 

Siemens. 

• Deployment involves four major aspects: seamless integration into existing building design and 

operation practices and platforms, lowering the cost of intelligent-building and enabling technologies, 

transforming markets to rapidly introduce new energy-efficient technologies, and a focus on conveying 

benefits that are desired in the marketplace (not only energy efficiency). 

• These technologies would apply to all buildings, but especially to existing commercial buildings 

and all new buildings. In addition, new technologies would be integrated into the building design and 

operation processes. 

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

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

September 2005). 

For more data on the Buildings sector, please refer to the “Buildings Energy Data Book” which is a 

comprehensive collection of buildings- and energy-related data. The Buildings Energy Data Book is 

available online at http://buildingsdatabook.eren.doe.gov/ 

54
Solar Buildings

Market Data U.S. Installations Source: EIA, Renewable Energy Annual 2004, Table 38, REA 2003 Table 18 and Table 10; REA 2002, Table 18(Thousands of Sq. Ft.) REA 1996, Table 18. 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Annual 

755 765 595 463 373 367 274 

Hot Water 

6,787 7,528 7,201 8,141 7,863 10,797 

Pool Heaters Total Solar Thermal 1 18,283 19,166 11,164 7,136 7,162 7,759 7,396 8,046 7,857 10,349 

6,763 

Cumulative 

755 1,520 2,115 2,578 2,951 3,318 3,592 

Hot Water 

6,763 13,550 21,078 28,279 36,420 44,283 55,080 

Pool Heaters Total Solar Thermal 1 62,829 153,035 199,459 233,386 240,548 248,307 255,703 263,749 271,606 281,955 1. Domestic shipments - total shipments minus export shipments U.S. Annual Shipments Source: EIA, Renewable Energy Annual 2003, Table 11; and REA 1999, Table 11. (Thousand Sq. Ft.) 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Total 19,398 N/A 11,409 7,666 7,616 8,138 7,756 8,583 8,354 11,189 Imports N/A 1,562 2,037 1,930 2,102 2,206 2,352 2,201 3,502 Exports 1,115 N/A 245 530 454 379 360 537 496 840 

U.S. Shipments by Cell Source: EIA Annual Energy Review 2004, Table 10.3; and Renewable 

Type (Thousand sq. ft.) 

1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 

Low-Temperature 12,233 N/A 3,645 6,813 6,821 7,524 7,292 8,152 7,948 10,919 

Collectors Medium-Temperature 7,165 N/A 2,527 840 785 606 443 427 400 268 

Collectors High-Temperature N/A N/A 5,237 13 10 7 21 4 5 2 Collectors Total 19,398 N/A 11,409 7,666 7,616 8,137 7,756 8,583 8,353 11,189 

55
U.S. Shipments of High-Temperature Source: EIA, Renewable Energy Annual 2003, Table 18; REA 2002, Table 18; R

Collectors by Market Sector, and End REA 1997, 1999-2000, Table 16; and REA 1998, Table 19. Use (Thousands of Sq. Ft.) 

1995 1996 1997 1998 1999 2000 2001 20

Market Sector 0 0 0 0 0 0  Residential 1 7 7 18 0 1 

 Commercial 0 2 0 0 0 0 

 Industrial 9 0 0 2 4 1 

 Utility 3 0 0 1 0 0 

 Other 13 10 7 21 4 2 

Total End Use 0 0 0 0 0 0 

 Pool Heating 0 7 7 18 0 0 

 Hot Water 0 0 0 0 0 0 

 Space Heating 1 0 0 0 0 0 

 Space Cooling 0 0 0 0 0 0  Combined Space and Water Heating 0 2 0 0 0 0 

 Process Heating 9 0 0 2 4 2 

 Electricity Generation 2 0 0 1 0 0 

 Other 13 10 7 21 4 2 

Total 0 0 0 0 0 0 

2000 data not published by EIA 

56
U.S. Shipments of Medium- Temperature Collectors by Source: EIA, Renewable Energy Annual 2003, Table 18; REA 2

Market Sector, and End Use (Thousands of Sq. Ft.) 1996, Table F9; REA 1997, 1999-2000, Table 16; and REA 199

1995 1996 1997 1998 1999 2000 2001 20

Market Sector Residential 774 728 569 355 366 238 

 Commercial 51 50 35 70 59 23 

 Industrial 12 1 0 18 0 5 

 Utility 0 0 0 0 0 

 Other 3 7 2 0 1 Total 839 786 606 443 426 268 

0 2 End Use 

 Pool Heating 32 21 11 36 12 16 

 Hot Water 743 754 588 384 373 231 

 Space Heating 62 6 2 13 24 9 

 Space Cooling 0 0 0 0 0 

 Combined Space and Water Heating 2 2 3 8 16 12  Process Heating 0 1 0 0 0 

0 Electricity Generation 0 0 0 0 0 

 Other 0 0 1 1 0 

0 Total 839 784 605 442 427 268 

0 2000 data not published by EIA 2 

57
U.S. Shipments of Low- Temperature Collectors Source: EIA, Renewable Energy Annual 2003, Table 18; REA 20

by Market Sector, and End Use (Thousands of 1996, Table F9; REA 1997, 1999-2000, Table 16; and REA 1998Sq. Ft.) 

1995 1996 1997 1998 1999 2000 2001 2002 

Market Sector Residential 6,192 6,146 6,791 6,810 7,408 9,885 10,519 

 Commercial 552 625 726 429 726 987 524 

 Industrial 69 51 7 44 18 12 2 

 Utility 0 0 0 0 0 0 0 

 Other 0 0 0 2 0 34 0 

Total 6,813 6,822 7,524 7,285 8,152 10,919 11,046 

End Use  Pool Heating 6,731 6,766 7,517 7,164 8,129 10,782 11,045 

 Hot Water 11 4 0 60 0 42 1 

 Space Heating 70 51 7 53 18 61 0  Space Cooling 0 0 0 0 0 0 0 

 Combined Space and Water Heating  Process Heating 0 0 0 0 5 34 0 

 Electricity Generation 0 0 0 0 0 0 0 

 Other 0 0 0 0 0 0 0 

Total 6,813 6,821 7,524 7,285 8,152 10,919 11,046 

2000 data not published by EIA 

58
Technology Performance 

Source: Arthur D. Little, Review of FY 2001 Office of Power Technology's Solar Building

Energy Production Summary, December 1999. 

1980 1985 1990 1995 2000 2005 2010 

Energy Savings 

DHW (kWh/yr) 2,750 Pool Heater (therms/yr) 1,600 

Source: Hot-Water Heater data from Arthur D. Little, Water-Heating Situation Analysis, N

Cost 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. 

For more data on the Buildings sector, please refer to the “Buildings Energy Data Book” which is a comprehensive collecenergy-related data. The Buildings Energy Data Book is available online at http://buildingsdatabook.eren.doe.gov/ 

59
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. 

Current Status 

• Commercially available engines have 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 efficiencies (LHV) of 70-80%. 

60
• 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 700-1,200° 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, 2003). 

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).” 

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. 

• Reciprocating-engine sales have grown more then fivefold 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 

In 1998, The U.S. Department of Energy – in partnership with the Gas Technology Institute, the 

Southwest Research Institute, and equipment manufacturers – joined 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. 

61
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 equivalent to current stateof-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. 

62
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 

Source: Debbie Haught, DOE, communication 2/26/02 - from Diesel and Gas 

Market Shipments Worldwide. (GW of units under 10 MW in size) 

1996 1997 1998 1999 

Diesel Recips 7.96 7.51 8.23 10.02 1

Gas Recips 0.73 1.35 1.19 1.63 

63
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 a 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. 

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). 

64
• 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 

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 acceptable cost target for microturbine energy is $0.05/kWh, which would present a cost 

advantage over most nonbaseload utility power. 

• "Ultra-clean, high-efficiency" microturbine product designs 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. 

65
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 200

Capstone 2 211 790 1,03

Other 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)CO 2 

SO 2 NO x CO PM 

Current 

670 - 1,180 g/kWh (17-30% efficiency) Negligible (natural gas) 9-25 ppm 

25-50 ppm 

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 

66
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 

Efficiency 26% (+/-2%) 28% (+/- 2%) 28% 30-33% 30% 

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 2000: 2 precommercial 

units, expected 

commercial in 2001 

2000: 20 units 

the European 

market 

Units Sold 2000: 790 units 

2001: 1,033 units 2001: 100 units 

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 

67
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%. 

• 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 combinedcycle applications. MCFCs have been operated on hydrogen, carbon monoxide, natural gas, propane, 

landfill gas, marine diesel, and simulated coal gasification products. 

• 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 

68
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 

• The cost of fuel cells hinders competition 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 are in the 250 kW-2 

MW range. 

Fuel Cell 

Type Electrolyte 

AFC 

PEMFC 

KOH 

Nafion 

PAFC Phosphoric 

Acid 

Operating 

Temp 

(°C) 

260 

65-85 

190-210 

Electrical 

Efficiency 

(% HHV) 

32-40 

30-40 

35-45 

Commercial 

Availability 

1960s 

2000-2001 

1992 

Typical Unit 

Size Range 

Startup time 

(hours) 

5-250 kW < 0.1 

200 kW 1-4 

69
MCFC 

Lithium, 

potassium, 

carbonate salt 

650-700 40-50 Post 2003 250 kW-2 

MW 5-10 

SOFC 

Yttrium & 

zirconium 750-1000 45-55 Post 2003 5-250 kW 5-10 

oxides 

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 can lead to technology 

applications where high temperature heat recovery has value. 

Technology Future 

• According to the Business Communications Company, the market for fuel cells was about $218 

million in 2000 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. 

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

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

September 2005); and National Renewable Energy Laboratory. Gas-Fired Distributed Energy Resource 

Technology Characterizations. NREL/TP-620/34783. November 2003. 

70
Fuel Cells 

Technology Performance 

Source: Hydrogen, Fuel Cells & Infrastructure Technologies Progra Development and Demonstration Plan, February 2005 

m Multi

Characteristic Units 

Small (3-25 kW) 

2004 Status 2005 2010 2004 Status 

Large 

Electrical Energy Efficiency @ rated power CHP Energy Efficiency @ rated power Cost Transient Response Time (from 10% to 90% power) Cold Start-up Time (to rated power @ -20 degrees C ambient) Continuous-use application Survivability (min and max ambient temperature) Durability @ <10% rated power degradation 

% % 

$/kW 

msec 

min 

C degrees 

hour 

3000 

30 32 35 75 75 80 

1500 1000 

<3 <3 <3 

<90 <60 <30 

-25 

+40 

-30 

+40 

-35 

+40 

>8,000 16,000 40,000 

30 75 

2500 

<3 

<90 

-25 

+40 

15,000 

2

71
Noise dB(A) <70 @ 1m <65 @ 1m <60 @ 1m <65 @ 1m 

@ 

Emissions g/ (Combined NOX, CO, SOX, 1,000 <15 <10 <9 <8 

Hydrocarbon, Particulates) kW a Includes fuel processor, stack, and all ancillaries.b Ratio of DC output energy to the LHV of the input fuel (natural gas or LPG) average value at rated power over life of powc For LPG, efficiencies are 1.5 percentage points lower than natural gas because the reforming process is more complex.d Ratio of DC output energy plus recovered thermal energy to the LHV of the input fuel (natural gas or LPG) average value of power plant e Includes projected cost advantage of high-volume production (2,000 units/year). Current cost does not include integrated power regulator necessary for black start. f Not applicable to backup power because this application does not use a fuel processor.

72
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, powerconversion 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 because 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. 

• Several advanced “flow batteries” are being developed. 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 zinc73
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. The major disadvantage is 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 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 $5.34 million and $1.71 million, respectively, in 2000. 

• Lead-acid battery manufacturers saw 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. 

• About 150 MW of utility peak-shaving batteries were in use in Japan in 2003. 

• In 2003, construction began on two 10-MW flow battery systems – one in the U.K. and the other in 

the United States. 

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 because 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. 

• Because 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. 

74
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. 

• The growing market for hybrid vehicles and the potential for “plug-in hybrid” vehicles--that could 

supply power to the grid as well as draw power from the grid—may increase future demand for batteries. 

• 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. 

• 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 (draft update, 

September 2005). 

75
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 

76
Technology Performance 

Grid-Connected Energy Storage Source: Sandia National Laboratories, Characteristics and Technologies for Technologies Costs and Efficiencies 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 Source: Sandia National Laboratories, Energy Storage Systems Program Requirements, and Potential Markets to Report for FY99, June 2000. 2010 According to Boeing 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 Capture Market Share 

24 Million 69,000 12,000 

77
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/yr 

Actual 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 

78
Advanced Energy Storage
 

Technology Description 

Advanced storage technologies under active development include processes that are mechanical 

(flywheels, pneumatic), electrochemical (advanced batteries, reversible fuel cells, hydrogen, 

ultracapacitors), and purely electrical (superconducting magnetic storage). Energy storage devices are 

added to the utility grid to improve productivity, increase reliability, or defer equipment upgrades. Energy 

storage devices must be charged and recharged with electricity generated elsewhere. Because the storage 

efficiency (output compared to input energy) is less than 100%, on a kilowatt-per-kilowatt basis, energy 

storage does not directly decrease CO2 production. The exception to this rule is the use of advanced 

energy storage in conjunction with intermittent renewable energy sources (such as photovoltaics and 

wind) that produce no direct CO2. Energy storage allows these intermittent resources to be dispatchable. 

Energy-storage devices do positively affect CO2 production on an industrial output basis by providing 

high-quality power, maximizing industrial productivity. New battery technologies, including sodium 

sulfur and flow batteries, significantly improve the energy and power densities for stationary battery 

storage as compared to traditional flooded lead-acid batteries. 

System Concepts 

• Stationary applications: Electric demand falls at night, providing an opportunity for the most cost 

effective electric generators to produce low cost power at night for storage. The stored energy could 

displace high cost, less efficient power normally produced at the peak during the day. CO2 emissions 

would be reduced if the efficiency of the energy storage were greater than 85%. Energy storage also can 

be used to alleviate the pressure on highly loaded components in the grid (transmission lines, 

transformers, etc.) 

These components are typically only loaded heavily for a small portion of the day. The storage system 

would be placed downstream from the heavily loaded component. This would reduce electrical losses of 

overloaded systems. Equipment upgrades also would be postponed, allowing the most efficient use of 

capital by utility companies. For intermittent renewables, advanced energy storage technology would 

improve their applicability. 

• Power quality and reliability: The operation of modern, computerized manufacturing depends directly 

on the quality of power the plant receives. Any voltage sag or momentary interruption can trip off a 

manufacturing line and electronic equipment. Industries that are particularly sensitive are semiconductor 

manufacturing; plastics and paper manufacturing; electronic retailers; and financial services such as 

banking, stock brokerages, and credit card-processing centers. If an interruption occurs that disrupts these 

processes, product is often lost, plant cleanup can be required, equipment can be damaged, and 

transactions can be lost. Any loss must be made up decreasing the overall efficiency of the operation, 

thereby increasing the amount of CO2 production required for each unit of output. Energy-storage value is 

usually measured economically with the cost of power-quality losses, which is estimated in excess of $1.5 

B/year in the United States alone. Industry is also installing energy-storage systems to purchase relatively 

cheap off-peak power for use during on-peak times. This use dovetails very nicely with the utilities’ 

interest in minimizing the load on highly loaded sections of the electric grid. Many energy-storage 

systems offer multiple benefits. This 5-MVA, 3.5-MWh valve-regulated lead-acid battery system is 

installed at a lead recycling plant in the Los Angeles, California, area. The system provides power-quality 

protection for the plant’s pollution-control equipment, preventing an environmental release in the event of 

a loss of power. The system carries the critical plant loads while an orderly shutdown occurs. The battery 

system also in discharged daily during the afternoon peak (and recharged nightly), reducing the plant’s 

energy costs. 

Technology Applications 

• For utilities, the most mature storage technology is pumped hydro; however, it requires topography 

with significant differences in elevation, so it’s only practical in certain locations. Compressed-air energy 

storage uses off-peak electricity to force air into underground caverns or dedicated tanks, and releases the 

air to drive turbines to generate on-peak electricity; this, too, is location-specific. Batteries, both 

79
m

conventional and advanced, are commonly used for energy-storage systems. Advanced flowing 

electrolyte batteries offer the promise of longer lifetimes and easier scalability to large, multi-MW 

systems. Superconducting magnetic energy storage (SMES) is largely focused on high-power, shortduration applications such as power quality and transmission system stability. Ultracapacitors have very 

high power density, but currently have relatively low total energy capacity and are also applicable for 

high-power, short-duration applications. Flywheels are now commercially viable in power quality and 

UPS applications, and emerging for high power, high-energy applications. 

• Each energy-storage system consists of four major components: the storage device (battery, flywheel, 

etc.); a power-conversion system; a control system for the storage system, possibly tied in with a utility 

SCADA (Supervisory Control And Data Acquisition) system or industrial facility control system; and 

interconnection hardware connecting the storage system to the grid. All common energy-storage devices 

are DC devices (battery) or produce a varying output (flywheels) requiring a power conversion system to 

connect it to the AC grid. The control system must manage the charging and discharging of the system, 

monitor the state of health of the various components, and interface with the local environment at a 

minimum to receive on/off signals. Interconnection hardware allows for the safe connection between the 

storage system and the local grid. 

Current Status 

Utilities 

Technology Efficiency Energy density Power density Sizes Comments 

[%] [W-h/kg] [kW/kg] [MW-h]____________________ 

Pumped hydro 75 0.27/100 m low 5,000-20,000 37 existing in U.S. 

Compressed gas 70 0 low 250-2,200 1 U.S., 1 German 

SMES 90+ 0 high 20 MW high-power apps 

Batteries 70–84 30-50 0.2-0.4 17-40 most common 

Flywheels 90+ 15-30 1-3 0.1-20 kWh US & foreign dev.

 Ultracapacitors 90+ 2-10 high 0.1-0.5 kWh

 high-power dens 

Technology Future 

• For utilities, only pumped hydro has made a significant penetration with approximately 21 GW. 

• Approximately 150 MW of utility peak-shaving batteries are in service in Japan. 

• Two 10-MW flow battery systems are under construction – one in the United Kingdom and the other 

in the United States. 

• Megawatt-scale power quality systems are cost effective and entering the marketplace today. 

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

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

September 2005). 

80
Superconducting Power Technology
 

Technology Description 

The United States’ ongoing appetite for clean, 

reliable, and affordable electricity has increased at a 

rate that seriously threatens to exceed current 

capacity. Demand is estimated to increase by an 

average rate of 1.8% per year for the next 20 years, 

yet investments in transmission and distribution 

infrastructure have not kept pace with those in 

generation. Furthermore, a majority of the new gasfired generation is not optimally sited where existing 

transmission assets are located. Witnessing the 

regional outages being experienced throughout the 

country – and those most recently highlighted in the 

northeast blackout of August 2003 – the 

inadequacies of the investment in infrastructure 

have, in effect, issued a wake-up call for 

modernizing and expanding grid capacity. Hightemperature superconducting (HTS) wires can carry many more times the amount of electricity of 

ordinary aluminum or copper wires. HTS materials were first discovered in the mid-1980s and are 

brittle oxide, or ceramic-like materials, that can carry electricity with virtually no resistance losses. 

Through years of federal research in partnership with companies throughout the nation, technology has 

developed to bond these HTS materials to various metals, providing the flexibility to fashion these 

ceramics into wires for use in transmission cables and for coils for power transformers, motors, 

generators, etc. Superconducting technologies make possible electric power equipment that is half the 

size of conventional alternatives, with half the energy losses. When HTS equipment becomes 

pervasive, up to 50% of the energy now lost in transmission and distribution will become available for 

customer use. HTS also will reduce the impact of power delivery on the environment and is helping 

create a new high-tech industry to help meet industry challenges due to delays in electric utility 

restructuring. Other benefits of superconducting electric power systems include improved grid stability, 

reliability, power quality, and deferred generation expansion. Affordability of capacity expansion is 

also enhanced, because underground superconducting cables require only 10% of the rights-of-way of 

conventional overhead transmission; and because HTS cables may be installed in conventional 

underground ducts without extensive street excavation. 

System Concepts 

• HTS cables have almost no resistance losses and can transport three-five times as much power as a 

conventional cable in the same size conduit. 

• HTS power transformers have about 30% reduction in total losses, can be 50% smaller and lighter 

than conventional units, may have a total ownership cost that is about 20% lower, are nonflammable, 

and do not contain oil or any other potential pollutant. In addition, there are electrical performance 

benefits associated with current limiting capacity and reduced impedance that will yield cost savings to 

power companies. 

• HTS Fault Current Limiters can provide power companies with surge protection within the 

transmission and distribution system. They are reusable, require minimal maintenance, and do not need 

replacement after being activated. 

• HTS motors rated at more than 750 kW would save enough energy over their lifetime to pay for the 

motor. Replacement of all U.S. motors greater than 750-kW with HTS motors would save consumers 

$2 billion per year in electricity costs. The motors are 50% smaller and lighter than conventional 

motors, as well. 

Source: American Superconductor 

81
• HTS generators with more than 100 MVA output will be more energy efficient, compact, and 

lighter than the conventional generator. The generator has characteristics that may help stabilize the 

transmission grid. 

System Components 

• HTS cables consist of large numbers of wires containing HTS materials operating at 65-77 K, 

insulated thermally and electrically from the environment. A cryogenic refrigerating system maintains 

the temperature of the cable at the desired operating temperature, regardless of the load on the cable. 

• HTS transformers use the same types of HTS materials as cables, formed into coils and mounted on 

conventional transformer cores. Electrical insulation is accomplished by means other than conventional 

oil-and-paper, and typically involves a combination of solid materials, liquid cryogens, and vacuum. 

HTS transformers may be overloaded for periods of time without loss of transformer life. 

• HTS motors, generators, magnetic separators, and current limiters use HTS wires and tapes in a coil 

form. Rotating cryogenic seals provide cooling for the rotating machines. 

• HTS flywheel systems use nearly frictionless bearings made from superconducting “discs,” cooled 

below the transition temperature of the HTS materials. 

Technology Applications 

• HTS wires: First generation “BSCCO” wires are available today in kilometer lengths at about 

$200/kA-m. Prototype, pre-commercial, second-generation “coated conductors” have been made in 

100 m lengths by industry and are to be scaled up in 2006-2008 to 1,000-m lengths. The 100-m tapes 

carry approximately 100 amperes of current in nitrogen. 

• HTS cables: Under the DOE Superconductivity Partnership with Industry (SPI), a team led by 

Southwire Company has installed and successfully tested a 30-m prototype cable that has been 

powering three manufacturing plants in Carrollton, Georgia, since February 2000. Three new HTS 

cable demonstration projects are underway with partial DOE funding from the SPI for 2006. A 600-m 

cable to be operated at 138-kV will be installed on Long Island, New York; and a 350-m distribution 

cable is installed in downtown Albany, New York. A section of the 350-m cable will also be 

manufactured using second-generation “coated conductors.” A 200-m HTS distribution cable carrying 

3,000 amperes is installed at a suburban substation in Columbus, Ohio. 

• HTS transformers: Waukesha Electric Systems, with partial DOE funding, demonstrated a 1-MVA 

single-phase prototype transformer in 1999 and is leading a team developing technology needed for 

electrical insulation that would be used for a pre-commercial, three-phase prototype transformer. 

• HTS motors: Rockwell Automation successfully demonstrated a prototype 750-kW motor in 2000 

and is researching motor components with improved performance characteristics. 

Current Status 

• The development at the national laboratories of ion-beam assisted deposition and rolling-assisted, 

biaxially textured substrate (RABiTSTM) technologies for producing high-performance HTS film 

conductors suitable for cables and transformers, and the involvement of four unique industry-led teams 

to capitalize on it, was a major success story for FY 1997. 

• The world’s first HTS cable to power industrial plants exceeded 28,000 hours of trouble-free 

operation in Carrollton, Georgia, (Southwire Company) in early 2005, and is the world’s longestrunning superconducting cable. The 30-m cable system has been operating unattended since June 2001. 

Short lengths of coated conductors made under stringent laboratory conditions exceeded the DOE goal 

of 1,000 A/cm width. 

• SuperPower verified greater than 80% current limiting performance of proof-of-concept Fault 

Current Limiter at up to 8,660 volts. 

• Rockwell Automation demonstrated a prototype 1000-HP synchronous motor that exceeded design 

specifications by 60%, and is now designing a motor that would use second-generation coated 

conductors with enhanced performance-to-cost ratio for the industrial marketplace. 

82
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. 

• 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. This team is now (in 2006) 

researching motor components. 

Technology Future 

High-temperature superconducting cables and equipment: Commercialization and market introduction 

requires development of inexpensive wires for transmission and distribution, and end uses such as 

electric motors. These wires are now under development under a government-industry partnership but 

are still years from wide-scale use. In addition, there is an international race underway to develop and 

deploy the new second-generation coated conductors. Numerous companies in Europe, Japan, Korea 

and China are pursuing the technologies first demonstrated by the national labs. Using hightemperature superconductivity wires to replace existing electric wires and cables may be analogous to 

the market penetration that occurred when the United States moved from copper wire to fiber optics in 

communications. Some pre-commercial demonstrations using commercial BSCCO wires are 

underway, but the Superconductivity Partnerships with Industry and the Second-Generation Wire 

Initiative could be expanded to include additional U.S. companies. The Power Delivery Research 

Initiative, authorized in the 2005 Energy Policy Act, would help enable broad utility involvement in the 

technology. 

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

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

September 2005). 

83
Superconducting Power Technology 

Market Data 

Source: Oak Ridge National Laboratory - High Temperature Superconduc

Projected Market for HTS devices 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 3

Generators 0 0 0 4.09 15.56 41.12 1

Cables 0 0.17 0.59 1.44 2.81 4.86 

Total 0 3.97 42.1 212.24 636.03 1554.2 3

The 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. 

Source: Analysis of Future Prices and Markets for High-Temperature Supe

Projected Market for HTS devices 2001, DOE. (Thousands of Dollars) 

2011 2013 2015 2017 2019 2021 

Motors 225 956 4,025 15,399 50,968 108,429 14Transformers 0 0 243 1,451 9,353 56,081 22

Generators 6,926 24,710 83,634 227,535 445,693 592,904 65

Cables 4,117 14,405 48,335 135,001 318,844 488,783 57

Total 11,270 40,071 136,236 379,386 824,857 1,246,196 1,59

84
Technology Performance 

Source: Oak Ridge National Laboratory – High-Temperature Superconduc

HTS Energy Savings 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 

Source: Analysis of Future Prices and Markets for High-Temperature Supe

HTS Energy Savings 2001, DOE. (GWh) 

2009 2011 2013 2015 2017 2019 

Motors 0 0 1 4 15 57 

Transformers 0 0 0 0 2 15 

Generators 2 11 44 171 556 1,417 

Cables 1 3 13 55 196 598 

Total 3 14 58 231 769 2,086 

85
Thermally Activated Technologies
 

Technology Description 

• 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. 

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 

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 

86
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. 

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. 

87
88
3.1 – States with Competitive Electricity Markets 

Purple-colored states (Figure 3.1.1) 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. 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, the law allows 

nonresidential customers retail access. 

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, last updated February 2003. 

Figure 3.1.1: Status of Restructuring of State Electricity Markets 

 89
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, energy

efficiency, and renewable energy. There are 15 states with SBCs (Table 3.2.1) through 

which a portion of the money will be used to support renewable resources. Together, 

these states will collect about $4 billion (Figure 3.2.1) in funds to support renewable 

resources between 1998 and 2017. 

S

http://www.ucsusa.org/clean_energy/clean_energy_p

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.

ource: Union of Concerned Scientists, June 2004 

olicies/state-clean-energy-maps-and-graphs.html

Figure 3.2.1: State System Benefit Funds 

 90
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 National Laboratory, April 2001.

Figure 3.2.2: Aggregation Annual and Cumulative State Funding

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 

SBC funding, so far, has supported the development of 707 MW of generating capacity

that is online. A further 1,548 MW of new capacity is still pending for a total of 163 

different projects. Nationwide, there is currently about $345 million in funding obligated 

through the respective SBC programs (Table 3.2.2). 

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)

 91
Table 3.2.2: State SBC Funding for Utility-Scale Renewable Projects

(as of September 2004)

Project 

Location

# of 

Projects

Original 

Dollars 

Obligated ($) 

Current 

Dollars 

Obligated ($) 

Capacity

Obligated 

(MW) 

Capacity

Cancelled 

(MW) 

Capacity

Pending 

(MW) 

Capacity

On-Line

(MW) 

CA 60 $243,573,376 $193,019,993 1,285.3 30.6 830.1 424.5 

IL 4 $9,305,000 $9,305,000 101.6 0.0 51.2 50.4 

MA 4 $19,469,093 $19,469,093 49.6 0.0 49.6 0.0 

MN 68 $61,841,977 $61,841,977 124.9 1.7 91.7 31.5 

NH* 1 $2,378,930 $2,378,930 50.0 0.0 50.0 0.0 

NJ 5 $14,590,000 $14,590,000 41.1 0.0 41.4 0.0 

NY 12 $26,560,000 $26,560,000 325.2 0.0 283.6 41.6 

OR 1 $3,800,000 $3,800,000 41.0 0.0 0.0 41.0 

PA 8 $17,600,000 $14,000,000 269.6 0.0 151.1 118.5 

Total 163 $399,118,376 $344,964,993 2,288.1 32.3 1,548.4 707.4 

*New Hampshire does not currently have a clean energy fund. The single project located in New Hampshire

is receiving support from Massachusetts’ clean energy fund. 

Source: Bolinger, M., R. Wiser, and G. Fitzgerald, 2004. The Impact of State Clean Energy Fund Support

for Utility-Scale Renewable Energy Projects. Prepared by Lawrence Berkeley National Laboratory and the

Clean Energy States Alliance, October. http://www.cleanenergystates.org/CaseStudies/LBNL56422_Utility-Scale_Renewables.pdf

Of the 163 projects announced, the vast majority – both in terms of number of projects 

and generating capacity – are wind power projects (Table 3.2.3). In descending order of 

capacity are geothermal, landfill gas, biomass, hydropower, waste tire, and digester gas. 

Table 3.2.3: Support for Utility-Scale Renewable Projects by Resource Type 

(as of September 2004)

Resource 

Type

# of 

Projects

Original 

Dollars 

Obligated ($) 

Current 

Dollars 

Obligated ($) 

Capacity

Obligated 

(MW) 

Capacity

Cancelled 

(MW) 

Capacity

Pending 

(MW) 

Capacity

On-Line

(MW) 

Biomass 8 $15,406,770 $11,466,832 85.2 9.5 64.4 11.3 

Digester 

Gas

3 $4,108,210 $4,108,210 6.0 0.0 3.9 2.1 

Geothermal 4 $80,331,618 $80,331,618 156.9 0.0 97.9 59.0 

Hydro 7 $12,977,258 $11,787,988 45.7 0.0 14.5 31.3 

Landfill Gas 28 $38,108,552 $31,098,469 90.7 19.8 35.1 35.8 

Waste Tire 1 $7,232,413 $3,287,461 30.0 0.0 30.0 0.0 

Wind 112 $240,953,555 $202,884,417 1,873.60 3.0 1,302.6 568.0 

Total 163 $399,118,376 $344,964,993 2,288.1 32.3 1,548.4 707.4 

Source: Bolinger, M., R. Wiser, and G. Fitzgerald, 2004. The Impact of State Clean Energy Fund Support

for Utility-Scale Renewable Energy Projects. Prepared by Lawrence Berkeley National Laboratory and the

Clean Energy States Alliance, October. http://www.cleanenergystates.org/CaseStudies/LBNL56422_Utility-Scale_Renewables.pdf

 92
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, 20 states plus Washington, 

D.C., have adopted RPS policies (Table 3.3.1) or renewable purchase obligations 

(Figure 3.3.1), while several other states have adopted nonbonding renewable energy

goals (Table 3.3.2). In addition, a number of states have increased their renewable energy

standards in recent years. In conjunction with system benefits funds, RPS policies are 

expected to lead to the development of more than 29,000 MW of new renewable energy

capacity by 2017 (Figure 3.3.2). 

S

Obligations by State 

Nevada: 20% by 2015

Hawaii: 20% by 2020

Texas:

5% by 2015

California: 

20% by 2017

Colorado: 10% by 2015

New Mexico:

10% by 2011

Arizona:

1.1% by 2007

Iowa: 2% by 1999

Minnesota: 19% by 2015*

Wisconsin:

2.2% by 2011

New York:

25% by 2013

Maine:

30% by 2000

MA:

4% by 2009

CT: 10% by 2010

RI:

16% by 2019

PA: 8% by 2020

NJ: 6.5% by 2008

MD: 7.5% by 2019

*Includes requirements adopted in 1994 and 2003 for one 

utility, Xcel Energy.

DC: 11% by 2022

DE: 10% by 2019

Montana: 15% by 2015

ource: NREL/Union of Concerned Scientists, October 2005

Figure 3.3.1: Renewable Portfolio Standards and Renewables Purchase 

 93
Table 3.3.1: State Renewable Portfolio Standards and Purchase Requirements 

State Purchase 

Requirements 

Eligible Resources Credit Trading Penalties 

AZ 15% by 2015 (of this 

30% must be customer 

sited) 

PV and solar thermal electric,

R&D, solar hot water, and instate landfill gas, wind, and

biomass. 

No central credit 

trading system 

Under 

consideratio

n 

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 

At discretion 

of CPUC 

CO 10% by 2015 Photovoltaics, Landfill Gas, 

Wind, Biomass, Geothermal

Electric, Anaerobic Digestion, 

Small Hydroelectric, Fuel Cells

(Renewable Fuels)

WREGIS system

under development 

To be 

determined 

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

DE 10% by 2019 Solar Thermal Electric,

Photovoltaics, Landfill Gas, 

Wind, Biomass, Hydroelectric,

Geothermal Electric, Anaerobic 

Digestion, Tidal Energy, Wave

Energy, Ocean Thermal, Fuel 

Cells (Renewable Fuels) 

Yes. GATS Penalty of

2.5¢/kWh

(increases to

5¢/kWh for

multi-year 

noncomplian

ce)

DC 11% by 2022 (0.386% 

solar) 

Solar Thermal Electric,

Photovoltaics, Landfill Gas, 

Wind, Biomass, Hydroelectric,

Geothermal Electric, Municipal

Solid Waste, Cofiring, Tidal

Energy, Wave Energy, Ocean 

Thermal 

Yes. GATS. 

Electric delivery

requirement to PJM

Penalty of

2.5¢/kWh for

tier 1 

resources, 

1¢/kWh for

tier II, and

30¢/kWh for 

PV 

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 

No Unspecified;

standard to 

be revisited 

if utilities can 

not meet it in

costeffective 

manner

IA Investor-owned utilities 

to purchase 105 MW

(~2% of 1999 sales) 

Solar, wind, methane recovery, 

and biomass 

No 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. Self-generation is

not eligible. Resource supply

under this definition exceeds 

RPS requirement. 

Yes. NEPOOL

Generation 

Information 

System. 

Possible

sanctions at

discretion of

PUC 

 94
State Purchase 

Requirements 

Eligible Resources Credit Trading Penalties 

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

MA 1% of sales to end-use 

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.

Noncomplying 

retailers

must submit 

a 

compliance 

plan.

Revocation

or 

suspension

of license is 

possible. 

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

MT 5% in 2008; 10% in 

2010; 15% in 2015 

Solar Thermal Electric,

Photovoltaics, Landfill Gas, 

Wind, Biomass, Hydroelectric,

Geothermal Electric, Anaerobic 

Digestion, Fuel Cells (Renewable 

Fuels) 

Yes. Electricity

must be delivered 

to MT. 

Penalty of

1¢/kWh

goes to 

universal

low-income

energy

assistance 

fund. 

NV 6% in 2005, rising to

20% by 2015. 

Minimum 5% 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. Financial 

penalties 

may be 

applied for 

noncomplian

ce. 

NJ Class I or II: 2.5% by

2008 

Class I: 4% by 2008, 

with solar requirement 

of 0.16% retail sales 

(90MW)

Goal of 20% by 2020. 

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. 

Yes. GATS. Alternative 

Compliance

Payment of 

5¢/kWh,

30¢/kWh for 

solar.

NM 5% of retail sales by

2006. Increase by 1%/yr 

to 10% by January 1,

Solar, wind, hydro (<=5 MW),

biomass, geothermal, and fuel

cells. 1 kWh solar = 3kWh; 1 

Yes. RECs valid for 

4 years from date

of issuance. 

At discretion 

of PUC. 

 95
State Purchase 

Requirements 

Eligible Resources Credit Trading Penalties 

2011 and thereafter. kWh biomass, geothermal, 

landfill gas, or fuel cells =2 kWh 

toward compliance 

NY 25% by 2013; 1% 

voluntary standard; 2% 

of total incremental RPS 

requirement (7.71%) is 

set-aside for customersited 

Photovoltaics, Landfill Gas, 

Wind, Biomass, Hydroelectric,

Fuel Cells, CHP/Cogeneration,

Biogas, Liquid Biofuel, Anaerobic 

Digestion, Tidal Energy, Wave

Energy, Ocean Thermal 

Possibly. Electricity

must be delivered 

to NY. 

Unspecified. 

PA 18% by 2020; 8% Tier 1

and 10% Tier II 

Solar set-aside of 0.5%

by 2020 

Solar Water Heat, Solar Space 

Heat, Solar Thermal Electric, 

Solar Thermal Process Heat, 

Photovoltaics, Landfill Gas, 

Wind, Biomass, Hydroelectric,

Geothermal Electric, Fuel Cells, 

Municipal Solid Waste, 

CHP/Cogeneration, Waste Coal, 

Coal Mine Methane, Coal

Gasification, Anaerobic 

Digestion, Other Distributed

Generation Technologies 

Yes. GATS Penalty of

4.5¢/kWh, 

for solar 

penalty is 

200% of PV 

REC value.

RI 16% by 2020; 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 co-firing, geothermal,

small hydropower, ocean, fuel

cells using hydrogen derived

from renewables

Yes. NEPOOL

Generation 

Information 

System. 

Penalty of

5¢/kWh can 

be made to 

Renewable 

Energy

Developmen

t Fund 

TX 5880 MW by 2015 

(5000 MW new)

Target of at least 500 

MW from renewables

other than wind 

Solar, wind, geothermal, hydro,

wave, tidal, biomass, including

landfill gas. New (operational 

after Sept. 1, 1999) or small

(<2MW) facilities eligible. 

Yes. ERCOT REC 

Trading System. 

Lesser of

5¢/kWh or 

200% of 

average 

market value 

of renewable

energy

credits. 

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.

Source: Table updated by NREL, March 2006. 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. 

 96
Table 3.3.2: State Renewable Energy Goals (Nonbinding)

State Purchase Requirements Eligible Resources 

Illinois 8% by 2013 (75% wind) Solar Water Heat, Solar Thermal Electric, 

Photovoltaics, Landfill Gas, Wind, Biomass,

Hydroelectric, CHP/Cogeneration, "Other Such 

Alternative Sources of Environmentally

Preferable Energy" 

Minnesota 1% by 2005 increasing by at least 

1%/year to 10% by 2015 

Wind, solar, hydro (<60 MW), and biomass 

Vermont Meet growth in electricity demand from

2005-2013 with renewable energy

sources (becomes mandatory in 2013 if

not met). 

Solar Thermal Electric, Photovoltaics, Landfill 

Gas, Wind, Biomass, Hydroelectric, Anaerobic 

Digestion, Fuel Cells (Renewable Fuels) 

Source: NREL, March 2006. 

Nationwide the RPS requirements for renewable energy are estimated to total 2,335 MW

of generating capacity. The vast majority (93.5%) is wind power, followed by biomass 

(2.3%), landfill gas (2.3%), hydropower (1.3%), solar energy (0.4%), and other (0.3%). 

The five largest states in terms of capacity are Texas, Minnesota, Iowa, California, and 

Wisconsin. 

Table 3.3.3 Estimated Renewable Energy Capacity Satisfying RPS Requirements 

Through 2003 (Megawatts, Nameplate Capacity)

State Biomass Hydro Landfill

Gas 

Solar 

Photovoltaic

s 

Wind Other/ 

Unknown

Total 

Arizona 0 0 5 9 0 0 14 

California 0 20 6 0 175 0 201 

Connecticut 0 0 0 0 0 0 0 

Maine 0 0 0 0 0 0 0 

Massachusetts 0 0 8 0 1 0 9 

Nevada 0 0 0 0 0 0 0 

New Jersey 0 0 0 0 0 0 0 

New Mexico 0 0 0 0 0 0 0 

Wisconsin 0 0 3 0 94 0 97 

Iowa 16 0 0 0 237 7 260 

Minnesota 25 0 0 0 476 0 501 

Texas 5 10 31 0.2 1,140 0 1,186 

Wisconsin 7 0 0 0 50 0 57 

Hawaii 0 0 0 0 0 0 0 

Illinois 0 0 0 0 0 0 0 

Minnesota 0 0 0 0 0 0 0 

Pennsylvania 0 0 0 0 10 0 10 

Total 53 30 53 9.2 2,183 7 2,335 

Share of Total 2.3% 1.3% 2.3% 0.4% 93.5% 0.3% 100.0%

Source: Petersick, T. 2004. State Renewable Energy Requirements and Goals: Status Through 2003, U.S. 

DOE Energy Information Administration, July http://www.eia.doe.gov/oiaf/analysispaper/rps/index.html

 97
2000

20012002200320042005200620072008

200920102011201220132014201520162017 

40,000 

*Projected development assuming states achieve annual RES targets.

**If achieved, IA, IL, and MN goals would support an additional 5,300 MW by 2017.

Source: Union of Concerned Scientists, November 2005. 

Figure 3.3.2: The Future Impact of State Purchase Mandates and Renewable

Energy Funds 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

Megawatts 

Hawaii 

California 

Nevada 

IA & WI 

New Jersey 

CT & RI 

MA 

Maine 

Minnesota 

AZ & NM 

New York 

Texas 

New renewable energy supported: 

- 29,000 MW by 2017** 

Maryland 

CO & MT 

Pennsylvania

DC & DE 

98
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. 

Most states have some type of net metering policy (Figure 3.4.1). Of the states that do 

have net metering policies (Table 3.4.1) the policies vary significantly in terms of the

maximum amount of capacity a consumer is permitted to net meter varies from 10 kW to 

2,000 kW. Some states only require certain types of utilities to offer net metering, 

exempting others. 

S

http://www.dsireusa.org/library/includes/top

State-wide net metering for certain utility types (e.g., IOUs only)

Net metering offered by one or more individual utilities

25 

kW

NH: 25

50 

kW

100

kW

50

10

100

25

1,000

MA: 60 25 RI: 25 *

DC: 100

DE: 25

50

100

40 20 25/100

2,000

150 40 

10/100

25

no limit

25/100

25/100

10

500

VT: 15/150

10/400

NJ: 2,000 

15

10 

100

25 MD: 80

50

varies

10

30

* CT: 100 

State-wide net metering for all utility types

* *

*

*

*

*

*

*

*

*

*

*

*

*

*

*

#s indicate system size limit (kW); in some cases limits are different for residential and commercial as shown

VA: 10 /500

*

20/100

*

ource: DSIRE database, January 2006 

ic.cfm?TopicCategoryID=6&CurrentPageID=10

Figure 3.4.1: Net Metering Policies by State 

 99
 100

Table 3.4.1: Summary of State Net Metering Policies 

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

Arizona – 

Salt River 

Project 

10 kW / 

Residential 

Photovoltaics None Purchased 

monthly by utility 

at average 

monthly market 

price minus a 

price adjustment 

of 

$0.00017/kWh 

(Utility 

guidelines) 

Salt River 

Project 

Arizona – 

Tucson 

Electric Power 

10 kW / 

Commercial, 

Residential 

Photovoltaics, 

Wind 

500 kW 

peak 

aggregate 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

(Utility 

guidelines) 

Tucson 

Electric 

Power 

Arkansas 25 kW for 

residential 

systems; 

100 kW for 

commercial 

systems 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells, 

Microturbines 

None Granted to utility 

monthly 

Yes All utilities 

California 1 MW (three 

biogas 

digesters up 

to 10 MW per 

unit may net 

meter) / 

Commercial, 

Industrial, 

Residential 

Photovoltaics, 

Landfill Gas, 

Wind, 

Anaerobic 

Digestion, 

Fuel Cells 

0.5% of a 

utility's peak 

demand 

(separate 

limit of 50 

MW for 

SDG&E) 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes All utilities1

Colorado 2 MW / 

Commercial, 

Industrial, 

Residential 

Solar, Landfill 

Gas, Wind, 

Biomass, 

Anaerobic 

Digestion, 

Small Hydro, 

Fuel Cells 

(Renewable 

Fuels) 

None Credited at retail 

rate to 

customer’s next 

bill; at end of 

each calendar 

year, customer 

reimbursed for 

NEG at utility’s 

average hourly 

incremental cost 

for the prior 12-

month period 

Yes Colorado 

utilities 

serving 

40,000 or 

more 

customers 

Colorado – 

Fort Collins 

Utilities 

10 kW / 

Residential 

Photovoltaics, 

Wind 

25 customers Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

Yes Fort Collins 

Utilities 

 

1

 In California, all utilities – with the exception of Los Angeles Department of Water & Power (LADWP) -- 

must offer net metering to customers with PV and wind-energy systems. (LADWP offers net metering 

voluntarily.) In addition, investor-owned utilities must offer net metering to customers with fuel cells and 

biomass-energy systems. 
 101

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

12-month billing 

cycle 

Colorado – 

Gunnison 

County 

Electric 

10 kW / 

Commercial, 

Residential 

Photovoltaics, 

Wind 

50 customers Purchased by 

utility at 

wholesale rate 

Yes Gunnison 

County 

Electric 

Colorado – 

Holy Cross 

Energy 

None / 

Commercial, 

Industrial, 

Residential 

Photovoltaics, 

Wind, 

Biomass, 

Hydro, 

Geothermal 

25 kW Credited at retail 

rate to 

customer's next 

bill; purchased 

by utility at 

wholesale rate 

at end of 12-

month billing 

cycle 

Yes Holy Cross 

Energy 

Connecticut 100 kW for 

renewables; 

50 kW for 

fossil fuels / 

Residential, 

Commercial 

Solar, Landfill 

Gas, Wind, 

Biomass, Fuel 

Cells, 

Municipal 

Solid Waste, 

Small Hydro, 

Tidal Energy, 

Wave Energy, 

Ocean 

Thermal 

None Purchased by 

utility at spotmarket energy 

rate 

Yes Investorowned 

utilities only 

Delaware 25 kW / 

Commercial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal 

None Varies by utility Yes All utilities 

(applies to 

municipal 

utilities if 

they opt to 

compete 

outside their 

limits) 

District of 

Columbia 

100 kW / 

Commercial, 

Industrial, 

Residential 

Renewables 

(unspecified), 

Fuel Cells, 

Microturbines, 

CHP 

None Credited at retail 

rate to 

customer's next 

bill 

Yes (under 

development) 

All utilities 

Florida – 

JEA 

10 kW / 

Residential 

Photovoltaics, 

Wind 

None Credited at retail 

rate to 

customer's next 

bill 

(Utility 

guidelines) 

JEA 

Florida – 

New Smyrna 

Beach Utilities 

10 kW / 

Commercial, 

Industrial, 

Residential 

Photovoltaics None Credited at retail 

rate to 

customer's next 

bill 

(Utility 

guidelines) 

New Smyrna 

Beach 

Utilities 

Georgia 100 kW for 

commercial 

systems; 

10 kW for 

residential 

systems; 

Photovoltaics, 

Wind, 

Fuel Cells 

0.2% of a 

utility’s 

annual peak 

demand 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

Yes All utilities 
 102

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

 cycle 

Hawaii 50 kW / 

Commercial, 

Residential, 

Government 

Photovoltaics, 

Wind, 

Biomass, 

Hydro 

0.5% of a 

utility's 

annual peak 

demand 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes All utilities 

Idaho – 

Idaho Power 

100 kW for 

large 

commercial 

and 

agricultural; 

25 kW for 

residential 

and small 

commercial 

Photovoltaics, 

Wind, 

Biomass, 

Hydro, Fuel 

Cells 

2.9 MW 

(0.1% of 

utility’s 2000 

peak 

demand) 

Purchased 

monthly by utility 

at retail rate for 

residential and 

small 

commercial 

customers; 

purchased at 

85% of Dow 

Jones index 

price for nonfirm energy for 

large 

commercial and 

agricultural 

customers 

(Utility 

guidelines) 

Idaho Power

Idaho – 

Utah Power & 

Light 

100 kW for 

large 

commercial 

and irrigation; 

25 kW for 

residential 

and small 

commercial 

Solar, Wind, 

Biomass, 

Hydro 

714 kW 

(0.1% of 

utility’s Idaho 

retail peak 

demand in 

2002) 

Purchased 

monthly by utility 

at retail rate for 

residential and 

small 

commercial 

customers; 

purchased at 

85% of Dow 

Jones index 

price for nonfirm energy for 

large 

commercial and 

agricultural 

customers 

(Utility 

guidelines) 

Utah Power 

& Light 

Idaho – 

Avista Utilities 

25 kW / 

Commercial, 

Residential, 

Agricultural 

Solar, Wind, 

Biomass, 

Hydro, Fuel 

Cells 

1.52 MW 

(0.1% of 

utility's 1996 

peak 

demand) 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

(Utility 

guidelines) 

Avista 

Utilities 

Illinois – 

ComEd Wind 

and PV 

Generation 

Program 

40 kW / 

All retail 

customers 

Photovoltaics, 

Wind 

0.1% of 

utility’s 

annual peak 

demand 

Purchased 

monthly by utility 

at avoided-cost 

rate; customer 

receives an 

annual incentive 

payment for 

production 

(Utility 

guidelines) 

ComEd 
 103

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

Indiana 10 kW / 

Residential, 

Schools 

Photovoltaics, 

Wind, 

Small Hydro 

0.1% of a 

utility’s most 

recent peak 

summer load

Credited at retail 

rate to 

customer's next 

bill 

Yes Investorowned 

utilities 

Iowa 500 kW / 

Commercial, 

Industrial, 

Residential 

Photovoltaics, 

Wind, 

Biomass, 

Hydro, 

Municipal 

Solid Waste 

None Credited at retail 

rate to 

customer's next 

bill 

No Investorowned 

utilities 

Kentucky 15 kW 

Commercial, 

Residential, 

Nonprofit, 

Schools, 

Agricultural, 

Institutional, 

Government 

Photovoltaics 0.1% of a 

utility’s 

single-hour 

peak load 

during the 

previous year

Credit at retail 

rate to 

customer's next 

bill 

(no expiration) 

Yes Investorowned 

utilities, 

cooperatives 

Louisiana 100 kW for 

commercial 

and 

agricultural 

systems; 25 

kW for 

residential 

systems 

Photovoltaics, 

Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells 

(Renewable 

Fuels), 

Microturbines 

None Credited at retail 

rate to 

customer's next 

bill indefinitely 

Yes All utilities 

Maine 100 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells, 

Municipal 

Solid Waste, 

CHP, Tidal 

Energy 

None Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

No All utilities 

Maryland 200 kW (500 

kW with 

MD PSC 

permission) / 

Commercial, 

Residential, 

Schools, 

Government 

Photovoltaics, 

Wind, 

Biomass 

34.7 MW 

(0.2% of 

state's 

adjusted 

peak load in 

1998) 

To be 

determined by 

MD Public 

Service 

Commission 

Yes All utilities 

Massachusetts 60 kW / 

Commercial, 

Industrial, 

Residential 

Renewables, 

CHP, Fuel 

Cells 

None Credited at 

average monthly 

market rate to 

customer’s next 

bill 

Yes All utilities 

Michigan 30 kW / 

Commercial, 

Industrial, 

Residential, 

Nonprofit, 

Schools, 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Municipal 

Solid Waste 

0.1% of a 

utility's peak 

load or 100 

kW 

(whichever is 

greater) 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

Yes Various 

utilities 

(voluntary 

participation)
 104

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

Government, 

Agricultural, 

Institutional 

cycle 

Minnesota 40 kW / 

Commercial, 

Industrial, 

Residential 

Photovoltaics, 

Wind, 

Biomass, 

Hydro, 

Municipal 

Solid Waste, 

CHP 

None Purchased at 

average retail 

utility energy 

rate 

Yes All utilities 

Montana 50 kW / 

Commercial, 

Industrial, 

Residential 

Photovoltaics, 

Wind, Hydro 

None Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes Investorowned 

utilities 

Montana – 

Montana 

Electric 

Cooperatives 

10 kW / 

Commercial, 

Residential 

Photovoltaics, 

Wind, 

Geothermal, 

Fuel Cells, 

Small Hydro 

None Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes Most of 

MEC’s 26 

member 

cooperatives

Nevada 150 kW2 / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal 

1% of a 

utility’s peak 

capacity 

Credited at retail 

rate to 

customer’s next 

bill; 

no expiration3

Yes Investorowned 

utilities 

New 

Hampshire 

25 kW / 

Commercial, 

Industrial, 

Residential 

Photovoltaics, 

Wind, Hydro 

0.05% of a 

utility's peak 

demand 

Credited at retail 

rate to 

customer's next 

bill 

Yes All utilities 

New Jersey 2 MW / 

Commercial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells 

(Renewable 

Fuels), Tidal 

Energy, Wave 

Energy 

None Credited at retail 

rate to 

customer's next 

bill; purchased 

by utility at 

avoided-cost 

rate at end of 

12-month billing 

cycle 

Yes All utilities 

New Mexico 10 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells, 

Municipal 

Solid Waste, 

None Credited to 

customer's next 

bill or purchased 

by utility at 

avoided-cost 

rate 

Yes Investorowned 

utilities, 

cooperatives

 

2

 In Nevada, utilities are permitted to require customers with systems of more than 30 kW in capacity to 

install a second meter at the customer’s expense. 

3

 In Nevada, it is unclear how NEG is treated for systems of more than 30 kW in capacity. 
 105

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

CHP, 

Microturbines 

New York 400 kW for 

farm waste; 

125 kW for 

farm-based 

wind; 25 kW 

for residential 

wind; 10 kW 

for solar 

Photovoltaics, 

Biomass, 

Wind 

Solar: 0.1% 

of a utility’s 

demand in 

1996; farm 

biogas: 0.4% 

of a utility’s 

demand in 

1996; wind: 

0.2% of a 

utility’s 2003 

demand 

Credited to 

customer's next 

bill – except 

NEG from wind 

systems over 10 

kW, which is 

credited to 

customer’s next 

bill at the utility’s 

avoided-cost 

rate. All NEG 

purchased by 

utility at avoidedcost rate at end 

of 12-month 

billing cycle. 

Yes All utilities 

North Carolina 20 kW 

residential; 

100 kW nonresidential 

Photovoltaics, 

Wind, 

Biomass 

0.2% of a 

utility’s North 

Carolina 

retail peak 

load for the 

previous year

Credited at retail 

rate to 

customer's next 

monthly bill; 

granted to utility 

every June 1 

and October 1 

Yes Investorowned 

utilities 

North Dakota 100 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Municipal 

Solid Waste, 

CHP 

None Purchased by 

utility at avoidedcost rate 

No Investorowned 

utilities 

Ohio 100 kW for 

microturbines; 

no limit for 

other systems 

/ 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Fuel Cells, 

Microturbines 

1% of a 

utility’s peak 

demand 

Credited at 

utility’s 

unbundledgeneration rate 

to customer’s 

next monthly bill

Yes All 

competitive 

utilities 

Ohio – 

 Bowling 

Green 

Municipal 

Utilities 

25 kW / 

Commercial, 

Residential 

Photovoltaics, 

Wind, Hydro, 

Fuel Cells 

None Negotiated with 

utility 

(Utility 

guidelines) 

Bowling 

Green 

Municipal 

Utilities 

Oklahoma 100 kW or 

25,000 

kWh/year 

(whichever is 

less) / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Municipal 

Solid Waste, 

CHP 

None Granted to utility 

monthly or 

credited to 

customer's next 

bill at utility’s 

avoided-cost 

rate (varies by 

utility) 

No All utilities 

Oregon 25 kW / 

Commercial, 

Solar, Wind, 

Hydro, Fuel 

0.5% of a 

utility's 

Credited at retail 

rate to 

Yes All utilities 
 106

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

Industrial, 

Residential 

Cells historic 

single-hour 

peak load 

customer's next 

bill or purchased 

by utility at 

avoided-cost 

rate 

Oregon – 

Ashland 

Electric 

None / 

Commercial, 

Residential 

Photovoltaics, 

Wind 

None Purchased by 

utility monthly at 

retail rate 

(1,000 

kWh/month 

maximum) 

(Utility 

guidelines) 

Ashland 

Electric 

Pennsylvania 

(new rules 

under 

development) 

Varies by 

utility / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro 

Varies by 

utility 

Varies by utility 

(granted to utility 

in most cases) 

Varies by utility All utilities 

Rhode Island 25 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells, 

Municipal 

Solid Waste, 

CHP 

1 MW 

(Narragansett 

territory) 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

No Narragansett 

Electric 

Texas 50 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Fuel Cells, 

Tidal Energy, 

Wave Energy, 

Microturbines 

None Purchased by 

utility monthly at 

avoided-cost 

rate 

Yes Most nonmunicipal 

utilities and 

noncooperatives 

Texas – 

San Antonio 

City Public 

Service 

25 kW / 

Commercial, 

Residential 

Photovoltaics, 

Wind, 

Biomass, 

Hydro, 

Geothermal, 

Tidal Energy, 

Wave Energy 

None Credited at retail 

rate to 

customer's next 

bill at utility's 

seasonal 

avoided-cost 

rate 

(Utility 

guidelines) 

San Antonio 

City Public 

Service 

Texas – 

Austin Energy 

20 kW / 

Commercial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Municipal 

Solid Waste 

1% of utility’s 

load 

Credited to 

customer's next 

bill 

(Utility 

guidelines) 

Austin 

Energy 

Utah 25 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Hydro, 

Fuel Cells 

0.1% of a 

utility's 2001 

peak demand 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes Investorowned 

utilities, 

cooperatives

Vermont 150 kW for 

farm systems; 

15 kW for 

Photovoltaics, 

Wind, 

Biomass, Fuel 

1% of a 

utility’s 1996 

peak demand 

Credited at retail 

rate to 

customer's next 

Yes All utilities 
 107

Program 

System Size 

Limit/ 

Customer 

Classes 

Eligible 

Eligible 

Technologies

Limit on 

Total 

Capacity 

Treatment of 

Net Excess 

Generation 

(NEG) 

Interconnection 

Standards for 

Net Metering 

Utilities 

Involved 

commercial 

and 

residential / 

Commercial, 

Residential, 

Agricultural 

Cells or peak 

demand 

during most 

recent 

calendar year 

(whichever is 

less) 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Virginia 500 kW for 

nonresidential; 

10 kW for 

residential / 

Commercial, 

Residential, 

Nonprofit, 

Schools, 

Government, 

Institutional 

Solar, Wind, 

Hydro 

0.1% of a 

utility’s 

annual peak 

demand 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes All utilities 

Washington 25 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Hydro, 

Fuel Cells 

0.1% of a 

utility’s 1996 

peak load 

Credited at retail 

rate to 

customer's next 

bill; granted to 

utility at end of 

12-month billing 

cycle 

Yes All utilities 

Washington – 

Grays Harbor 

PUD 

25 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Hydro, 

Fuel Cells 

0.1% of 

utility’s 1996 

peak load 

Purchased by 

utility annually at 

50% of 

retail rate 

Yes Grays 

Harbor PUD

Wisconsin 20 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro, 

Geothermal, 

Municipal 

Solid Waste, 

CHP 

None Purchased by 

utility at retail 

rate 

(renewables) or 

avoided-cost 

rate (nonrenewables) 

Yes Investorowned 

utilities 

Wyoming 25 kW / 

Commercial, 

Industrial, 

Residential 

Solar, Wind, 

Biomass, 

Hydro 

None Credited at retail 

rate to 

customer's next 

bill; purchased 

by utility at 

avoided-cost 

rate at end of 

12-month billing 

cycle 

Yes All utilities 

Sources: The Interstate Renewable Energy Council (IREC) and the N.C. Solar Center (NCSC). 

"Connecting to the Grid" Project Web site, http://www.irecusa.org/connect; Database of State Incentives for 

Renewable Energy (DSIRE), http://www.dsireusa.org, March 2006. Additional information, including most 

legislative and regulatory source citations, is available via DSIRE. 
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, 25 states and the District of Columbia have environmental disclosure 

policies in place (Figure 3.5.1), 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, January 2006. 

http://www.dsireusa.org/index.cfm?&CurrentPageID=10

Figure 3.5.1: Environmental Disclosure Requirements by State 

D.C.

State has a Disclosure Rule

 108
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 investor-owned utilities, rural electric cooperatives, and other publicly owned 

utilities. More than 600 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.

Customers 

At the end of 2004, more than 500,000 electricity customers nationally were purchasing

green power products through regulated utility companies, from green power marketers 

in a competitive market setting, or in the form of RECs (Table 3.6.1). In aggregate, 

utility green pricing programs have shown steady growth in customers over time as the

number of utility programs has increased and as existing programs have grown. On the

other hand, competitive markets have been less consistent. While green power sales have 

grown in Texas and some Northeast states, other markets have failed altogether—most 

notably in California and Connecticut. While REC customers represent a small fraction 

of the total customer base, REC sales have increased dramatically because of a number of

very large purchases. 

Average participation rates among utility green pricing programs have remained steady at 

just more than 1%, although the top performing utility green pricing programs have 

achieved rates ranging from 4% to 15%. Competitive markets have experienced 

penetration rates of from 1% to 2% in states where the market has been conducive to

retail competition. 

 109
Table 3.6.1: Estimated Green Power Customers by Market Segment

2000 2001 2002 2003 2004 

Utility Green Pricing 130,000* 170,000* 230,000* 270,000 330,000 

Competitive Markets >160,000** >110,000** ~150,000 >150,000 >180,000 

REC Markets -- -- < 10,000 < 10,000 < 10,000 

Retail Total >290,000 >280,000 ~390,000 ~430,000 ~520,000 

* Annual program participant numbers have been adjusted downward from those originally reported in Bird 

and Swezey (2003), because of program participation revisions made by the Los Angeles Department of 

Water and Power. 

** Includes only customers purchasing Green-e certified green power products, as reported by the Center for 

Resource Solutions (2001; 2002). 

Sales 

Retail sales of renewable energy in voluntary purchase markets experienced strong

growth in 2004, increasing more than 60% to 6.2 billion kWh annually. This includes 

sales of renewable energy derived from both new and preexisting renewable energy

sources. REC sales nearly tripled, while sales through utility green pricing programs and 

competitive marketers also exhibited strong annual growth of about 40%. 

Table 3.6.2: Estimated Green Power Sales by Market Segment

(million kWh)

2003 2004 Increase 

Utility Green Pricing 1,280 1,840 43% 

Competitive Markets 1,900 2,650 40% 

REC Markets 660 1,720 162% 

Retail Total 3,840 6,210 62% 

*Includes sales of new and existing renewable energy. 

Purchases by residential customers represent slightly more than half of total renewable

energy sales in voluntary markets. In 2004, nonresidential customers accounted for 30% 

and 20% of total renewable energy sales in green pricing programs and competitive

markets, respectively, and nearly all REC sales. 

Since 2000, the amount of renewable energy capacity serving green power markets has 

increased more than tenfold. At the end of 2004, more than 2,200 MW of new renewable 

energy generation capacity was being used to supply green power markets, with another 

450 MW planned. 

 110
Table 3.6.3: Estimated Green Power Sales by Customer Segment, 2004 

(million kWh)

Green 

Pricing 

Competitive 

Markets 

REC 

Markets Total Share 

Residential 1,300 2,140 40 3,480 56% 

Nonresidential 540 510 1,690 2,740 44% 

Total 1,840 2,650 1,720 6,210 100% 

 Totals may not add due to rounding. 

Table 3.6.4: Estimated New Renewables Capacity Supplying Green Power Markets,

2000-2004 (megawatts)

Market 2000 2001 2002 2003 2004 

Utility Green Pricing 77 221 279 510 706 

Competitive Markets/RECs 90 542 695 1,126 1,528 

Total 167 764 974 1,636 2,233 

Totals may not add due to rounding. 

Source: Bird and Swezey (2005). 

Table 3.6.5: New Renewables Capacity Supplying Green Power Markets, 2004 

Source MW in Place % MW Planned %

Wind 2,045.6 91.6 364.5 80.1 

Biomass 135.6 6.1 58.8 12.9 

Solar 8.1 0.4 0.4 0.1 

Geothermal 35.5 1.6 0.0 0.0 

Small Hydro 8.5 0.4 31.3 6.9 

Total 2,233.3 100.0 455.0 100.0 

Source: L.Bird and B. Swezey, Estimates of New Renewable Energy Capacity

Serving U.S. Green Power Markets (2004), National Renewable Energy Laboratory, September 2005. 

http://www.eere.energy.gov/greenpower/resources/tables/new_gp_cap.shtml

 111
3.7 – 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 and 

expand business lines and expertise prior to electric market competition. To date, more 

than 600 investor-owned, municipal, and cooperative utilities in 34 states have either 

implemented or announced plans to offer a green pricing option (Figure 3.7.1). 

Source: L. Bird and B. Swezey, National Renewable Energy Laboratory. Updated May 2005. 

http://www.eere.energy.gov/greenpower/markets/pricing.shtml?page=4

Figure 3.7.1: Number of Utilities Offering Green Pricing Programs by State 

 112
Table 3.7.1: New Renewable Energy Capacity Supplying Green Pricing Programs 

in 2004 (megawatts)

Source Installed Planned 

Wind 584.0 82.8% 139.7 61.1% 

Biomass 76.3 10.8% 57.5 25.1% 

Solar 6.1 0.9% 0.2 0.1% 

Geothermal 30.5 4.3% 0.0 0.0% 

Small Hydro 8.5 1.2% 31.3 13.7% 

Total 705.5 100.0% 228.7 100.0%

Source: Bird and Brown (2005) 

Table 3.7.2: Estimated Cumulative Number of Customers Participating in Utility

Green Pricing Programs 

Customer Segment 1999 2000 2001 2002 2003 2004 

Residential na* 131,000 166,300 224,500 258,700 323,700 

Nonresidential na* 1,700 2,500 3,900 6,500 8,100 

Total 66,900 132,700 168,800 228,400 265,000 331,800 

% Annual Growth na 98% 27% 35% 16% 25% 

% Nonresidential na 1.3% 1.5% 1.7% 2.4% 2.5% 

 *Information on residential and nonresidential participants is not available for 1999. 

 Source: Bird and Brown (2005) 

Table 3.7.3: Customer Participation Rates in Utility Green Pricing Programs 

by Year 

1999 2000 2001 2002 2003 2004 

Average 0.9% 1.2% 1.3% 1.2% 1.2% 1.3% 

Median 0.8% 0.7% 0.7% 0.8% 0.9% 1.0% 

Top 10 

programs 

for 

participation

* 

2.1%–4.7%# 2.6%–7.3% 3.0%–7.0% 3.0%–5.8% 3.9%–1.1% 3.8%–

4.5% 

*The high end of the range declined from 2000 to 2002, because the utility with the highest participation rate 

(Moorhead Public Service) experienced an increase in its overall customer base, while the number of 

participants in its green pricing program remained steady. The program was fully subscribed in 2000, and 

the utility has not attempted to expand it. 

#Data for April 2000 source: Bird and Brown (2005) 

 113
Table 3.7.4: Annual Sales of Green Energy through Utility Green Pricing Programs 

(million kWh)

2000 2001 2002 2003 2004 

Residential customers --- 399.7 661.3 874.1 1,295.0 

Nonresidential customers --- 172.8 233.7 410.3 544.2 

Total All customers 453.7 572.5 895.0 1,284.4 1,839.2 

% Annual Growth 26% 56% 44% 43% 

% Nonresidential Customers --- 30% 26% 32% 30% 

*Sales information for customer segments not available for 2000. 

 Source: Bird and Brown (2005) 

Table 3.7.5: Price Premiums Charged for Utility Green Pricing Products 

(¢/kWh) 

1999 2000 2001 2002 2003 2004 

Average 2.15 3.48 2.93 2.82 2.62 2.45 

Median 2.00 2.50 2.50 2.50 2.00 2.00 

Range 0.4–5.0 (0.5)–20.0 0.9–17.6 0.7–17.6 0.6–17.6 0.33–

17.6 

10 Programs with Lowest 

Premiums* 0.4–2.5** (0.5)–2.5 1.0–1.5 0.7–1.5 0.6–1.3 0.33–1.0 

Number of Programs

Represented 24 50 60 80 91 101 

*Represents the 10 utility programs with the lowest price premiums for new customer-driven renewable

energy. This includes only programs that have installed – or announced firm plans to install or purchase 

power from – new renewable energy sources. In 2001, the discrepancy between the low end of the range for 

all programs and the Top 10 programs was because the program with the lowest premium (0.9¢/kWh) was 

not eligible for the Top 10, because it was either selling existing renewables or had not installed any new

renewable capacity for its program. 

**Data for April 2000. 

Source: Bird and Brown (2005) 

 114
Table 3.7.6: Utility Green Pricing Programs by State, October 2005 

State Utility Name 

Program 

Type

Start 

Name Date Premium 

AK Golden Valley Electric Association Sustainable Natural

Alternative Power (SNAP) 

various local

projects 

2005 Contribution

AL Alabama Power Company Renewable Energy Rate biomass cofiring 2003 6.0¢/kWh

AL TVA: City of Athens Electric

Department, Cullman Electric Coop, 

Cullman Power Board, Decator 

Utilities, Florence Utilities, Hartselle 

Utilities, Huntsville, Joe Wheeler 

EMC, Muscle Shoals Electric Board, 

Scottsboro Electric Power Board, 

Sheffield Utilities, Tuscumbia Electric 

Department

Green Power Switch landfill gas, 

PV, wind 

2000 2.67¢/kWh

AZ Arizona Public Service APS Solar Partners Program central PV 1997 17.6¢/kWh

AZ Salt River Project EarthWise Energy central PV, 

wind, landfill

gas, small

hydro, 

geothermal

1998/ 

2001 

3.0¢/kWh

AZ Tucson Electric GreenWatts landfill gas, PV 2000 10¢/kWh

AZ UniSource Energy Services GreenWatts PV 2004 10¢/kWh

CA Anaheim Public Utilities Green Power for the Schools PV 2002 Contribution

CA Anaheim Public Utilities Green Power for the Grid wind, landfill

gas 

2002 1.5¢/kWh

CA Burbank Water and Power Clean Green Support various 2001 1.0¢/kWh

CA Los Angeles Department of Water 

and Power

Green Power for a Green LA wind, landfill

gas 

1999 3.0¢/kWh

CA PacifiCorp: Pacific Power Blue Sky Block wind 2000 1.95¢/kWh

CA Palo Alto Utilities/3 Phases Energy

Services

Palo Alto Green wind, PV 2003 1.5¢/kWh

CA Pasadena Water & Power Green Power wind 2003 2.5¢/kWh

CA Roseville Electric RE Green Energy geothermal, 

PV 

2000 1.0¢/kWh

CA Sacramento Municipal Utility District Greenergy wind, landfill

gas, hydro, PV 

1997 1.0¢/kWh or 

$6/month 

CA Silicon Valley Power / 3 Phases

Energy Services

Santa Clara Green Power wind, PV 2004 1.5¢/kWh

CO Colorado Springs Utilities Green Power wind 1999 3.0¢/kWh

CO Holy Cross Energy Wind Power Pioneers wind 1998 2.5¢/kWh

CO Holy Cross Energy Local Renewable Energy

Pool

small hydro, 

PV 

2002 3.3¢/kWh

CO Platte River Power Authority: Estes

Park, Fort Collins Utilities, Longmont 

Power & Communications, Loveland 

Water & Light

Wind Energy Premium wind 1999 1.0¢/kWh -

2.5¢/kWh

 115
Program 

State Utility Name Name Type

Start 

Date Premium 

CO Tri-State Generation & Transmission: 

Carbon Power, Chimney Rock, 

Gunnison County Electric, Kit Carson 

Electric, La Plata Electric, Mountain

Parks Electric, Mountain View

Electric, New Mexico, Northwest 

Rural, Poudre Valley Rural Electric

Association, Public Power District, 

San Isabel Electric, San Luis Valley

Rural Electric Coop, San Miguel 

Power, Sangre, Springer Electric, 

United Power, White River (18 of 44 

coops offer program)

Renewable Resource Power 

Service

wind, hydro 1998 2.5¢/kWh

CO Xcel Energy Renewable Energy Trust PV 1993 Contribution

CO Xcel Energy WindSource wind 1997 0.97¢/kWh

CO Yampa Valley Electric Association Wind Energy Program wind 1999 3.0¢/kWh

FL City of Tallahassee/Sterling Planet Green for You biomass, PV 2002 1.6¢/kWh

FL City of Tallahassee/Sterling Planet Green for You PV only 2002 11.6¢/kWh

FL Florida Power & Light / Green 

Mountain Energy

Sunshine Energy biomass, wind, 

PV 

2004 0.975¢/kWh

FL Gainesville Regional Utilities GRUgreen Energy landfill gas, 

wind, PV 

2003 2.0¢/kWh

FL Keys Energy Services / Sterling 

Planet

GO GREEN: Florida Ever 

Green

solar hot water, 

PV, biomass 

2004 2.75¢/kWh

FL Keys Energy Services / Sterling 

Planet

GO GREEN: USA Green wind, 

biomass,PV 

2004 1.60¢/kWh

FL Tampa Electric Company (TECO) Tampa Electric's Renewable 

Energy Program

PV, landfill

gas, biomass 

co-firing 

2000 5.0¢/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 2.0¢/kWh3.3¢/kWh

GA Georgia Power Green Energy landfill gas 2005 5.5¢/ kWh

GA TVA: Blue Ridge Mountain Electric

Membership Corporation, North 

Georgia Electric Membership 

Corporation

Green Power Switch landfill gas, 

PV, wind 

2000 2.67¢/ kWh

HI Hawaiian Electric Sun Power for Schools PV in schools 1997 Contribution

ID Avista Utilities Buck-A-Block wind 2002 0.33¢/kWh

ID Idaho Power Green Power Program various 2001 Contribution

ID PacifiCorp: Utah Power Blue Sky wind 2003 1.95¢/kWh

 116
Program 

State Utility Name Name Type

Start 

Date Premium 

ID Vigilante Electric Cooperative Alternative Renewable 

Energy Program

wind, PV, 

hydro 

2003 1.1¢/kWh

IL CCS/Soyland and Community

Energy, Inc (8 of 11 coops offer 

program): Adams Electric Co-op, 

Coles-Moultrie Electric, Eastern Illini 

Electric, McDonough Power, Menard, 

Rural Electric Convenience Co-op, 

Shelby Electric, Spoon River Electric 

Co-op

EcoEnergy wind 2005 3.0¢/kWh

IL City of Naperville / Community

Energy

Renewable Energy Option wind, small 

hydro, PV 

2005 2.5¢/kWh

IL City of St. Charles/ComEd and

Community Energy

TBD wind, landfill

gas 

2003 Contribution

IL Dairyland Power Cooperative: JoCarroll Energy/ElizabethEvergreen Renewable 

Energy Program

wind 1997 1.5¢/kWh

IN Hoosier Energy (5 of 17 coops offer 

program): 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¢/kWh4.0¢/kWh

IN Indianapolis Power & Light Elect Plan Green Power 

Program

geothermal 1998 0.9¢/kWh

IN PSI Energy/Cinergy Green Power Rider wind, PV, 

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¢/kWh1.0¢/kWh

IA Alliant Energy Second Nature landfill gas, 

wind 

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¢/kWh2.5¢/kWh

IA Cedar Falls Utilities Harvest the Wind wind 2000 2.5¢/kWh

IA Corn Belt Power Cooperatives (5 of 

11 co-ops): Butler County REC, 

Franklin REC, Grundy County REC,

Humboldt County REC, Sac County

REC

Energy Wise Renewables wind 2003 1.5¢/kWh

IA Dairyland Power Cooperative: 

Allamakee-Clayton/Postville, 

Hawkeye Tri-County/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

 117
Program 

State Utility Name Name Type

Start 

Date Premium 

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, 

PV 

2003 Varies by

utility

IA MidAmerican Energy Renewable Advantage wind 2004 Contribution

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 1.0¢/kWh2.5¢/kWh

IA Muscatine Power and Water Solar Muscatine PV 2004 Contribution

IA Waverly Light & Power Green Power Choice wind 2003 Contribution

IA Waverly Light & Power Iowa Energy Tags wind 2001 2.0¢/kWh

KY East Kentucky Power Cooperative: 

Blue Grass Energy, Clark, 

Cumberland, Fleming, Grayson, 

Inter-county Energy, Jackson, 

Licking, Mason, Nolin, Owen Electric, 

Salt River, Shelby, South Kentucky

EnviroWatts landfill gas 2002 2.75¢/kWh

KY TVA: Bowling Green Municipal

Utilities, Franklin Electric Plant Board

Green Power Switch landfill gas, 

PV, wind 

2000 2.67¢/kWh

MA Concord Municipal Light Plant 

(CMLP)

Green Power hydro 2004 3.0¢/kWh

MI Consumers Energy Green Generation wind, landfill

gas 

2005 1.67¢/kWh

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 1.5¢/kWh

MI Upper Peninsula Power Company NatureWise wind, landfill

gas and animal 

waste methane 

2004 4.0¢/kWh

 118
Program 

State Utility Name Name Type

Start 

Date Premium 

MI We Energies Energy for Tomorrow wind, landfill

gas, hydro 

2000 2.0¢/kWh

MN Alliant Energy Second Nature landfill gas, 

wind 

2002 2.0¢/kWh

MN Basin Electric Power Cooperative: 

Minnesota Valley Electric Coop, 

Sioux Valley Southwestern

Prairie Winds wind 2002 1.0¢/kWh2.5¢/kWh

MN Central Minnesota Municipal Power 

Agency

Green Energy Program wind, landfill

gas 

n/a 1.5¢/kWh2.5¢/kWh

MN Dairyland Power Cooperative: 

Freeborn-Mower Cooperative / Albert 

Lea, People's / Rochester, Tri-County

/ Rushford

Evergreen Renewable 

Energy Program

wind 1997 1.5¢/kWh

MN Great River Energy (all 28 coops 

offer program): Agralite, Arrowhead, 

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,

Nobles Cooperative Electric, North 

Itasca, Redwood Electric

Cooperative, Runestone Electric, 

South Central Electric Association ,

Stearns Electric, Steele-Waseca, 

Todd-Wadena , Wright-Hennepin 

Electric

Wellspring Renewable Wind 

Energy Program

wind 1998 1.45¢/kWh2.0¢/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 munis offer program): 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 1.0¢/kWh2.5¢/kWh

MN Moorhead Public Service Capture the Wind wind 1998 1.5¢/kWh

MN Otter Tail Power Company TailWinds wind 2002 2.6¢/kWh

 119
Program 

State Utility Name Name Type

Start 

Date Premium 

MN Southern Minnesota Municipal Power 

Agency (all 18 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

SMMPA Wind Power wind 2000 1.0¢/kWh

MN Xcel Energy WindSource wind 2003 2.0¢/kWh

MS TVA: City of Oxford, North East 

Mississippi Electric Power

Asssociation, Starkville Electric

System

Green Power Switch landfill gas, 

PV, wind 

2000 2.67¢/kWh

MO Boone Electric Cooperative Renewable Choice wind 2003 2.0¢/kWh

MO City Utilities of Springfield WindCurrent wind 2000 5.0¢/kWh

MT Basin Electric Power Cooperative: 

Lower Yellowstone

Prairie Winds wind 2000 1.0¢/kWh2.5¢/kWh

MT Northwestern Energy E+ Green wind, PV 2003 2.0¢/kWh

MT Park Electric Cooperative Green Power Program wind, hydro 2002 1.2¢/kWh

MT Southern Montana Electric 

Generation and Transmission 

Cooperative (5 co-ops): Fergus

Electric, Yellowstone Valley, Bear 

Tooth Electric, Mid Yellowstone, and

Tongue River

Environmentally Preferred 

Power 

wind, hydro 2002 1.05¢/kWh

MT Vigilante Electric Cooperative Alternative Renewable 

Energy Program

wind, hydro, 

PV 

2003 1.1¢/kWh

NE Lincoln Electric System LES Renewable Energy

Program

wind 1998 4.3¢/kWh

NE Omaha Public Power District Green Power Program landfill gas, 

wind 

2002 3.0¢/kWh

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 Los Alamos Department of Public

Utilities

Green Power wind 2005 1.8¢/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

NC Dominion North Carolina Power NC GreenPower biomass, wind, 

solar

2003 4.0¢/kWh

NC Duke Power NC GreenPower biomass, wind, 

solar

2003 4.0¢/kWh

 120
Program 

State Utility Name Name Type

Start 

Date Premium 

NC ElectriCities: City of High Point, City

of Laurinburg, City of Newton, City of 

Shelby, City of Statesville, town of 

Apex, Town of Granite Falls

NC GreenPower biomass, wind, 

solar

2003 4.0¢/kWh

NC NC Electric Cooperatives (15 of 27 

cooperatives offer the program): 

Albemarle EMC, Blue Ridge Electric

Membership Corp., Brunswick

Electric Membership Corp., Carteret 

Craven Electric Coop., EdgecombeMartin County Electric Membership

Corp., EnergyUnited, Four County

Electric Membership Corp., Haywood 

Electric Membership Corp., JonesOnslow Electric Membership Corp., 

Pee Dee Electric Membership Corp., 

Piedmont Electric Membership Corp., 

Randolph Electric Membership Corp., 

Roanoke Electric Membership Corp., 

Tri-County Electric Membership 

Corp., Wake Electric Membership 

Corp.

NC GreenPower biomass, wind, 

PV 

2003 4.0¢/kWh

NC Progress Energy / CP&L NC GreenPower biomass, wind, 

solar

2003 4.0¢/kWh

NC TVA: Mountain Electric Cooperative Green Power Switch landfill gas, 

PV, wind 

2000 2.67¢/kWh

ND Basin Electric Power Cooperative (49 

coops offer program in 5 states): 

Oliver Mercer Electric Coop, Morgran-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¢/kWh2.5¢/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 1.0¢/kWh2.5¢/kWh

OH American Municipal Power-Ohio / 

Green Mountain Energy: City of 

Bowling Green, Cuyahoga Falls, 

Wyandotte

Nature's Energy small hydro, 

landfill gas, 

wind 

2003 1.3¢/kWh1.5¢/kWh

OK OG&E Electric Services OG&E Wind Power wind 2003 2.0¢/kWh

OK Oklahoma Municipal Power Authority:

Tonkawa, Altus, Frederick, Okeene, 

Prague Municipal Utilities and 

Edmond Electric

Pure & Simple wind 2004 1.8¢/kWh

 121
Program 

State Utility Name Name Type

Start 

Date Premium 

OK Western Farmers Electric

Cooperative (19 of 19): Alfalfa 

Electric Cooperative, Caddo Electric

Cooperative, Canadian Valley

Electric Cooperative, Choctaw Electri 

Cooperative, Cimmaron Electric

Cooperative, Cotton Electric 

Cooperative, East Central Oklahoma 

Electric Cooperative, Harmon Electric 

Cooperative, Kay Electric

Cooperative, Kiamichi Electric

Cooperative, Kiwash Electric

Cooperative, Northfork Electric

Cooperative, Northwestern Electric

Cooperative, Oklahoma Electric

Cooperative, People's Electric

Cooperative, Red River Valley Rural 

Electric Cooperative, Rural Electric

Cooperative, Southeastern Electric

Cooperative, Southwest Rural 

Electric Cooperative

WindWorks wind 2004 0.5¢/kWh

OR City of Ashland/Bonneville 

Environmental Foundation

Renewable Pioneers PV, wind 2003 2.0¢/kWh

OR Columbia River PUD Choice Energy wind 2005 2.0¢/kWh

OR Emerald People's Utility

District/Green Mountain Energy

Choose Renewable

Electricity

wind, 

geothermal

2003 1.2¢/kWh

OR Eugene Water & Electric Board EWEB Wind Power wind 1999 0.71¢/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 PacifiCorp: Pacific Power Blue Sky QS (Commercial 

Only)

wind 2004 Sliding scale 

depending 

on size

OR PacifiCorp: Pacific Power Blue Sky Block wind 2000 1.95¢/kWh

OR PacifiCorp: Pacific Power / 3 Phases

Energy Services

Blue Sky Usage wind, biomass, 

PV 

2002 0.78¢/kWh

OR PacifiCorp: Pacific Power / 3 Phases

Energy Services

Blue Sky Habitat wind, biomass, 

PV 

2002 0.78¢/kWh + 

$2.50/mo.

donation 

OR Pacific Northwest Generating 

Cooperative: Central Electric

Cooperative, Clearwater Power, 

Consumers Power, Douglas Electric

Cooperative, Umatilla Electric 

Cooperative (5 of 16 coops offer 

program)

Green Power landfill gas 1998 1.8¢/kWh4.0¢/kWh

OR Portland General Electric / Green 

Mountain Energy

Green Source existing 

geothermal, 

wind 

2002 0.8¢/kWh

OR Portland General Electric / Green 

Mountain Energy

Healthy Habitat existing 

geothermal, 

wind 

2002 0.8¢/kWh + 

$2.50/mo.

donation 

OR Portland General Electric Company Clean Wind for Medium to 

Large Commercial &

Industrial Accounts

wind 2003 1.35¢/kWh1.7¢/kWh

 122
Program 

State Utility Name Name Type

Start 

Date Premium 

OR Portland General Electric Company Clean Wind Power wind 2002 1.75¢/kWh

SC Santee Cooper, Aiken Electric

Cooperative, Berkeley Electric

Cooperative, Edisto Electric

Cooperative, Fairfield Electric

Cooperative, Horry Electric

Cooperative, Laurens Electric 

Cooperative, Lynches River Electric

Cooperative, Marlboro Electric

Cooperative, Mid-Carolina Electric

Cooperative, Palmetto Electric

Cooperative, Pee Dee Electric

Cooperative, Santee Electric

Cooperative, Tri-County Electric 

Cooperative, York 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, ClayUnion Electric Corporation, 

Codington-Clark Electric 

Cooperative, Dakota Energy

Cooperative, Douglas Electric

Cooperative, FEM Electric

Association, H-D Electric

Cooperative, Kingsbury Electric

Cooperative, Lyon-Lincoln Electric

Cooperative, McCook Electric 

Cooperative, Northern Electric

Cooperative, Oahe Electric

Cooperative, Renville-Sibley Coop. 

Power Assn., 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¢/kWh2.5¢/kWh

SD Missouri River Energy Services: City

of Vermillion

RiverWinds wind 2002 1.0¢/kWh2.5¢/kWh

TN TVA: 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, 

Green Power Switch landfill gas, 

PV, wind 

2000 2.67¢/kWh

 123
Program 

State Utility Name Name Type

Start 

Date Premium 

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, 

Memphis Light, Gas & Water,

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

TX Austin Energy (City of Austin) GreenChoice wind, landfill

gas, hydro 

2000/19

97 

0.5¢/kWh

TX City Public Service of San Antonio Windtricity wind 2000 3.0¢/kWh

TX El Paso Electric Company Renewable Energy Tariff wind 2001 1.92¢/kWh

UT City of St. George Clean Green Power wind, small 

hydro 

2005 2.95¢/kWh

UT Deseret Power GreenWay various 2004 1.95¢/kWh

UT Pacificorp: Utah Power Blue Sky wind 2000 1.95¢/kWh

VT Central Vermont Public Service CVPS Cow Power biogas 2004 4.0¢/kWh

VT Green Mountain Power CoolHome / CoolBusiness wind, biomass 2002 Contribution

WA Avista Utilities Buck-A-Block wind 2002 0.33¢/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 Clallam County PUD Green 

Power Program

landfill gas 2001 0.7¢/kWh

WA Clark Public Utilities Green Lights PV, wind 2002 1.5¢/kWh

WA Cowlitz PUD Renewable Resource 

Energy

wind, PV 2002 2.0¢/kWh

 124
Program 

State Utility Name Name Type

Start 

Date Premium 

WA Grant County PUD Alternative Energy

Resources Program

wind 2002 2.0¢/kWh

WA Grays Harbor PUD Green Power 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 wind, hydro 1999 3.5¢/kWh

WA Pacific County PUD Green Power landfill gas 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 Plan wind, PV, 

biogas 

2002 2.0¢/kWh

WA Seattle City Light Green UP (C&I only) wind 2005 1.5¢/kWh

WA Seattle City Light Seattle Green Power PV, biogas 2002 Contribution

WA Snohomish County Public Utility

District

Planet Power wind 2002 2.0¢/kWh

WA Tacoma Power EverGreen Options small hydro, 

wind 

2000 1.5¢/kWh

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, 

Polk-Burnett / Centuria, Price /

Phillips, Richland, Riverland / 

Arcadia, St. Croix / Baldwin, Scenic 

Rivers / Lancaster, Taylor / Medford, 

Vernon / Westby

Evergreen Renewable 

Energy Program

wind 1998 1.5¢/kWh

WI Great River Energy: Head of the 

Lakes

Wellspring Renewable Wind 

Energy Program

wind 1997 1.45¢/kWh2.0¢/kWh

WI Madison Gas & Electric Wind Power Program wind 1999 3.3¢/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 1.86¢/kWh

WI Wisconsin Public Service Solar Wise for Schools PV in schools 1996 Contribution

 125
Program 

State Utility Name Name Type

Start 

Date Premium 

WY Lower Valley Energy Green Power wind 2003 1.17¢/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

WY Yampa Valley Electric Association Wind Energy Program wind 1999 3.0¢/kWh

 126
3.8 – Competitive Green Power Offerings and Renewable Energy

Certificates 

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 (Figure 3.8.1). 

Renewable energy certificates (RECs) – also known as green tags, renewable energy

credits, or tradeable renewable certificates – present 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). See our list below of

organizations that offer green certificate products.

Source: L. Bird and B. Swezey, National Renewable Energy Laboratory. Updated July 2005. 

http://www.eere.energy.gov/greenpower/markets/marketing.shtml?page=4

Figure 3.8.1: Green Power Marketing Activity in Competitive Electricity Markets 

 127
Based on data received from green power marketers, an estimated 200,000 retail 

customers were purchasing green power from competitive suppliers – or in the form of 

RECs – at the end of 2004. Most of these customers are purchasing green power from 

competitive suppliers in states with retail competition, primarily in the Northeast and 

Texas, including about 30,000 participants in utility/marketer programs. Of the total, 

fewer than 10,000 retail customers purchase REC products (Table 3.8.1), with most 

customers concentrated in the Mid-Atlantic and Northeast states where REC marketers 

tend to be most active. In competitive markets, the vast majority of customers purchasing

green power are residential customers, while the fraction of nonresidential customers 

purchasing RECs is higher – on the order of one-fifth. 

Table 3.8.1: Estimated Number of Customers Purchasing RECs or Green Power

from Competitive Marketers, 2002-2004 

2002 2003 2004 

Competitive Markets ~150,000 >150,000 >180,000 

RECs <10,000 <10,000 <10,000 

Total <160,000 ~160,000 ~190,000 

Table 3.8.2: Retail Sales of Renewable Energy in Competitive Markets and RECs 

(million kWh)

2003 2004 

Competitive Markets 

Residential na 2,140 

Nonresidential na 510 

Subtotal 1,900 2,650 

RECs

Residential na 40 

Nonresidential na 1,690 

Subtotal 660 1,720 

Total Sales 2,560 4,370 

na = not available 

An estimated 1,530 MW of new renewables capacity is used to supply competitive green power markets, or

is being sold as RECs in both retail and wholesale markets; wind energy is the predominant resource type. 

More than 225 MW of additional renewables capacity is planned, again dominated by wind.

An estimated 4.4 billion kWh of renewable energy was sold to retail customers by

competitive and REC marketers. About 2.7 billion kWh of this total was sold to retail 

customers bundled with electricity in competitive electricity markets – a 40% increase 

from 2003. This figure includes renewable energy from both existing and new sources, as 

well as that sold to customers in products that contain only a small percentage of 

renewable energy. It also includes sales of renewable energy through default 

utility/supplier programs or utility/marketer partnership in states with retail competition, 

 128
which totaled 136 million kWh. Retail sales of RECs, which are sold separate from 

electricity and largely derived from new renewable energy sources, grew nearly

threefold, reaching 1.7 billion kWh in 2004. 

Table 3.8.3: New Renewables Capacity Supplying Competitive Markets 

and Renewable Energy Certificates, 2004 

Source MW in Place % MW Planned %

Wind 1,461.6 95.7 224.8 99.3 

Biomass 59.3 3.9 1.3 0.6 

Solar 2.0 0.1 0.2 0.1 

Geothermal 5.0 0.3 0.0 0.0 

Small Hydro 0.0 0.0 0.0 0.0 

Total 1,527.9 100.0 226.3 100.0 

Source: L.Bird and B. Swezey, Estimates of New Renewable Energy Capacity

Serving U.S. Green Power Markets (2004), National Renewable Energy Laboratory, September 2005. 

http://www.eere.energy.gov/greenpower/resources/tables/new_gp_cap.shtml

Table 3.8.4: Estimated Wholesale RECs Supplying Voluntary Markets, 2003 

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 3.8.5: 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 

 129
Table 3.8.6: Voluntary Market Wholesale REC Prices for New Sources by Type and 

Region ($/MWh)

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 3.8.7: Voluntary Market Wholesale REC Prices for Existing Sources by Type 

and Region ($/MWh)

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. 

 130
Table 3.8.8: Retail Green Power Product Offerings in Competitive Electricity

Markets, October 2005

State Company Product Name Residential 

Price 

Premium1 

Fee Resource Mix2 Certification

CT Community Energy

(CT Clean Energy

Options Program)

CT Clean Energy

Options 50% or 

100% of usage

1.1¢/kWh — 50% new wind, 50% 

landfill gas 

—

CT Levco 100% Renewable 

Electricity Program

0.0¢/kWh — 98% waste-toenergy and hydro 

(Class II), 2% new

solar, wind, fuel 

cells, and landfill 

gas 

—

CT Sterling Planet (CT

Clean Energy Options 

Program)

Sterling Select 50%

or 100% of usage

1.15¢/kWh — 33% new wind, 33% 

existing small low

impact hydro, 34% 

new landfill gas 

—

DC PEPCO Energy

Services (3)

Green Electricity

10%, 51% or 100% 

of usage

1.35¢/kWh (for 

100% usage)

— landfill gas —

DC PEPCO Energy

Services (3)

NewWind Energy

51% or 100% of 

usage

2.05¢kWh (for 

100% usage)

— new wind —

DC Washington Gas 

Energy Services / 

Community Energy

New Wind Energy

(5%, 10%, 25%, 

50%, or 100% of

usage)

2.5¢/kWh — new wind —

ME Maine Renewable 

Energy/Maine 

Interfaith Power & 

Light (4)

Maine Clean Power 2.37¢/kWh — 100% low impact 

hydro 

—

ME Maine Renewable 

Energy/Maine 

Interfaith Power & 

Light (4)

Maine Clean Power 

Plus

2.87¢/kWh — 80% low impact 

hydro, 20% wind 

—

MD PEPCO Energy

Services (5)

Green Electricity

10%, 51% or 100% 

of usage 

2.75¢/kWh (for 

100% usage)

— landfill gas —

MD PEPCO Energy

Services (5)

NewWind Energy

51% or 100% of 

usage

3.35¢/kWh (for 

100% usage)

— new wind —

MD PEPCO Energy

Services (5)

Non-residential

product

NA — 50% to 100% 

eligible renewables 

Green-e

MD Washington Gas 

Energy Services / 

Community Energy

New Wind Energy 2.5¢/kWh — new wind (5%, 

10%, 25%, 50%, or 

100% of usage) or 

100 kWh blocks

—

MA Cape Light Compact 

(6)

Cape Light Compact 

Green 50% or 100%

1.768¢/kWh

(for 100% 

usage)

— 75% small hydro, 

24% new wind or 

landfill gas, 1% new

solar

—

MA Massachusetts

Electric/Nantucket 

Electric/Community

Energy

New Wind Energy

50% or 100% of 

usage

2.4¢/kWh — 50% small hydro, 

50% new wind 

Green-e

 131
State Company Product Name Residential 

Price 

Premium1 

Fee Resource Mix2 Certification

MA Massachusetts

Electric/Nantucket 

Electric/Mass Energy

Consumers Alliance

New England 

GreenStart 50% or 

100% of usage

2.4¢/kWh (for 

100% usage) 

— 75% small hydro, 

19% biomass, 5% 

wind, 1% solar 

(≥25% of total is

new) 

— 

MA Massachusetts

Electric/Nantucket 

Electric/Sterling 

Planet

Sterling Premium 

50% or 100% of 

usage

1.35¢/kWh — 50% small hydro, 

30% bioenergy, 

15% wind, 5% new

solar

Environmental 

Resources

Trust

NJ Green Mountain 

Energy Company (7)

Enviro Blend 1.0¢/kWh $3.95/mo. 5% new wind, 0.4%

solar, 44.6% 

captured methane, 

50% large hydro 

— 

NJ PSE&G/JCP&L/ 

Community Energy

Clean Power Choice 

Program 

1.3¢/kWh — 50% wind, 49% low

impact hydro, 1% 

solar

— 

NJ PSE&G/JCP&L/ 

Green Mountain 

Energy

Clean Power Choice 

Program 

0.9¢/kWh — 50% wind, 50% low

impact hydro 

— 

NJ PSE&G/JCP&L/ 

Jersey-Atlantic Wind 

Clean Power Choice 

Program 

2.9¢/kWh — 50% wind, 50% low

impact hydro 

— 

NJ PSE&G/JCP&L/ 

Jersey-Atlantic Wind 

Clean Power Choice 

Program: New

Jersey Wind Energy

5.5¢/kWh — 100-kWh new wind — 

NJ PSE&G/JCP&L/ 

Sterling Planet 

Clean Power Choice 

Program 

1.2¢/kWh — 33% wind, 33% 

small hydro, 34% 

bioenergy

Environmental 

Resources

Trust

NY ConEdison Solutions 

(8) / Community

Energy

GREEN Power 0.5¢/kWh — 25% new wind, 

75% small hydro 

Green-e 

NY ECONnergy Keet It Clean $.10/day for 

100kWh

— 100% new wind — 

$.20/day for 

200kWh

NY Energy Cooperative of 

New York (9)

Renewable 

Electricity

0.5¢/kWh to 

0.75¢/kWh

— 25% new wind, 

75% existing landfill 

gas 

— 

NY Long Island Power 

Authority / Community

Energy

New Wind Energy 2.5¢/kWh — new wind — 

NY Long Island Power 

Authority / Community

Energy

New Wind Energy

and Water

1.3¢/kWh — 60% new wind, 

40% small hydro 

— 

NY Long Island Power 

Authority / EnviroGen

Green Power 

Program

1.0¢/kWh — 75% landfill gas, 

25% small hydro 

— 

NY Long Island Power 

Authority / Sterling 

Planet

New York Clean 1.0¢/kWh — 55% small hydro, 

35% bioenergy, 

10% wind 

— 

NY Long Island Power 

Authority / Sterling 

Planet

Sterling Green 1.5¢/kWh — 40% wind, 30% 

small hydro, 30% 

bioenergy

— 

NY NYSEG/Community 

Energy

Catch the Wind/New

Wind Energy

2.5¢/kWh — 100-kWh blocks of 

new wind 

— 

 132
State Company Product Name Residential 

Price 

Premium1 

Fee Resource Mix2 Certification

NY Niagara Mohawk / 

Community Energy

60% New Wind 

Energy and 40%

Small Hydro

1.0¢/kWh — 60% new wind, 

40% hydro 

— 

NY Niagara Mohawk / 

Community Energy

NewWind Energy 2.0¢/kWh — new wind — 

NY Niagara Mohawk / 

EnviroGen

Think Green! 1.0¢/kWh — 75% landfill gas, 

25% hydro 

— 

NY Niagara Mohawk / 

Sterling Planet

Sterling Green 1.5¢/kWh — 40% wind, 30% 

small hydro, 30% 

bioenergy

Environmental 

Resources

Trust

NY Niagara 

Mohawk/Green 

Mountain Energy

Green Mountain 

Energy Electricity

1.3¢/kWh — 50% small hydro, 

50% wind 

Green-e 

NY Rochester Gas &

Electric/Community

Energy

Catch the 

Wind/NewWind 

Energy

2.5¢/kWh — 100-kWh blocks of 

new wind 

— 

NY Suburban Energy

Services /Sterling

Planet

Sterling Green

Renewable 

Electricity

1.5¢/kWh — 40% new wind, 

30% small hydro, 

30% bioenergy

— 

PA Energy Cooperative of 

Pennsylvania (10)

EcoChoice 100 2.78¢/kWh — 89% landfill gas, 

10% wind, 1% solar 

Green-e 

PA Energy Cooperative of 

Pennsylvania (10)

Wind Energy 2.5¢/kWh — wind — 

PA PECO 

Energy/Community

Energy (10)

PECO Wind 2.54¢/kWh — 100-kWh blocks of 

new wind 

— 

PA PEPCO Energy

Services (10)

Green Electricity

10%, 51% or 100% 

of usage

3.7¢/kWh (for 

100% usage) 

— 100% renewable — 

PA PEPCO Energy

Services (10)

NewWind Energy

51% or 100% of 

usage

4.48¢/kWh (for 

100% usage) 

— 100% new wind — 

RI Narragansett Electric / 

Community Energy, 

Inc.

NewWind Energy

50% or 100% of 

usage

2.0¢/kWh — 50% small hydro, 

50% new wind 

Green-e 

RI Narragansett Electric / 

People's Power & 

Light

New England 

GreenStart RI 50% 

or 100% of usage

1.5¢/kWh — 69% small hydro, 

30% new wind, 1% 

new solar 

Green-e 

RI Narragansett Electric / 

Sterling Planet

Sterling Supreme

100%

1.98¢/kWh — 40% small hydro, 

25% biomass, 25% 

new solar, 10% 

wind 

Environmental 

Resources

Trust

TX Gexa Energy (11) Gexa Green -1.1¢/kWh — 100% renewable — 

TX Green Mountain 

Energy Company (11)

100% Wind Power: 

Reliable Rate or

Month-to-Month

1.46¢/kWh $5.34/mo. wind — 

TX Green Mountain 

Energy Company (11) 

Pollution Free:

Reliable Rate or

Month-to-Month 

-0.03¢/kWh $5.34/mo. wind and hydro — 

TX Reliant Energy (11) Renewable Plan -1.1¢/kWh — wind — 

VA PEPCO Energy

Services (12)

Green Electricity

10%, 51% or 100% 

of usage

4.53¢/kWh (for 

100% usage) 

— landfill gas — 

 133
State Company Product Name Residential 

Price 

Premium1 

Fee Resource Mix2 Certification

VA PEPCO Energy

Services (12)

NewWind Energy

51% or 100% of 

usage

5.33¢/kWh (for 

100% usage) 

— new wind — 

VA Washington Gas 

Energy Services / 

Community Energy

New Wind Energy

Certificates

2.5¢/kWh — 100 kWh blocks of 

new wind 

— 

1 Prices updated as of July 2005 and may also apply to small commercial customers. Prices may differ for 

large commercial/industrial customers and may vary by service territory.

2 New is defined as operating or repowered after January 1, 1999 based on the Green-e TRC certification

standards. 

3 Offered in PEPCO service territory. Product prices are for renewal customers based on annual average 

costs for customers in PEPCO's service territory (6.8¢/kWh).

4 Price premium is for Central Maine Power service territory based on standard offer of 7.13¢/kWh.

5 Product offered in Baltimore Gas and Electric and PEPCO service territories. Price is for PEPCO service 

territory based on price to compare of 6.55¢/kWh.

6 Price premium is based on a comparison to the Cape Light Compact's standard electricity product. 

7 Green Mountain Energy offers products in Conectiv, JCPL, and PSE&G service territories. Product prices

are for PSE&G (price to compare of 6.503¢/kWh). 

8 Price premium is based on a comparison to ConEdison Solutions' standard electricity product in the 

ConEdison service territory.

9 Price premium is for Niagara Mohawk service territory. Program only available in Niagara Mohawk service

territory. Premium varies depending on energy taxes and usage. 

10 Product prices are for PECO service territory (price to compare of 6.21¢/kWh). 

11 Product prices are based on price to beat of 12.1¢/kWh for TXU service territory (specifically Dallas, 

Texas) (Except where noted). Except for Gexa Green, which is listed in price per kWh, prices based on 1000 

kwh of usage monthly, and include monthly fees. 

12 Products are available in Dominion Virginia Power service territory

 134
Table 3.8.9: Renewable Energy Certificate (REC) Retail Products, October 2005 

Certificate Marketer Product Name

Renewable 

Resources 

Location of 

Renewable 

Resources 

Residential 

Price 

Premiums* Certification 

3 Phases Energy Services Green 

Certificates

100% new wind Nationwide 2.0¢/kWh Green-e 

Blue Sky Energy Corp Greener 

ChoiceTM Green 

Tags

Landfill Gas Utah 1.95¢/kWh — 

Bonneville Environmental

Foundation

Green Tags ≥98% new

wind, ≤1% new

solar, ≤1% new

biomass 

Washington, 

Oregon, 

Wyoming,

Montana, Alberta

2.0¢/kWh Green-e 

Clean and Green Clean and Green 

Membership 

100% new wind National 3.0¢/kWh Green-e 

Clean Energy

Partnership/Community

Energy

Mid Atlantic Wind 100% new wind Mid Atlantic 2.0¢/kWh Green-e 

Clean Energy

Partnership/Sterling Planet

National New

Clean Energy MIx

24% wind, 25% 

biomass, 50% 

landfill gas, 1% 

solar

National 0.6¢/kWh Environmental 

Resources Trust 

Clean Energy

Partnership/Sterling Planet

National and 

Regional New

Wind

100% new wind National 1.0¢/kWh Environmental 

Resources Trust 

Community Energy New Wind 

Energy

100% new wind Colorado, Illinois, 

New York, 

Pennsylvania, 

West Virginia

2.0¢/kWh -

2.5¢/kWh

Green-e 

Conservation Services

Group

ClimateSAVE 95% new wind, 

5% new solar 

Kansas (wind), 

New York (solar)

1.65¢/kWh - 

1.75¢/kWh

Green-e 

EAD Environmental 100% Wind

Energy

Certificates

100% new wind Not specified 1.5¢/kWh — 

EAD Environmental Home Grown 

Hydro Certificates

100% small 

hydro (<5MW)

New England 1.2¢/kWh — 

Green Mountain Energy TBD

(Pennsylvania 

REC product) 

100% wind National 1.7¢/kWh2.0¢/kWh— 

Maine Interfaith Power & 

Light/BEF

Green Tags 

(supplied by BEF)

≥98% new

wind, ≤1% new

solar, ≤1% new

biomass 

Washington, 

Oregon, 

Wyoming,

Montana, Alberta

2.0¢/kWh — 

Mass Energy Consumers 

Alliance

New England 

Wind

100% new wind Massachusetts 5.0¢/kWh — 

NativeEnergy CoolHome New biogas and 

new wind 

Vermont and 

Pennsylvania 

(biomass), South 

Dakota (wind) 

0.8¢/kWh -

1.0¢/kWh

** 

NativeEnergy WindBuilders 100% new wind South Dakota ~1.2¢/kWh, ** 

$12 per ton of 

CO2 avoided 

Renewable Choice Energy American Wind 100% new wind Nationwide 2.0¢/kWh Green-e 

 135
Certificate Marketer Product Name

Renewable 

Resources 

Location of 

Renewable 

Resources 

Residential 

Price 

Premiums* Certification 

Renewable Ventures PVUSA Solar 

Green 

Certificates

100% solar California 3.3¢/kWh Green-e 

SKY energy, Inc. Wind-e

Renewable 

Energy

100% new wind Nationwide 2.4¢/kWh Green-e 

Sterling Planet Green America 45% new wind, 

50% new

biomass, 5% 

new solar 

Nationwide 1.6¢/kWh Green-e 

TerraPass Inc. TerraPass Various

(including 

efficiency and

CO2 offsets) 

Nationwide ~$11/ton CO2 — 

Waverly Light & Power Iowa Energy

Tags

100% wind Iowa 2.0¢/kWh — 

WindCurrent Chesapeake 

Windcurrent

100% new wind Mid-Atlantic 

States 

2.5¢/kWh Green-e 

Premium may also apply to small commercial customers. Large users may be able to negotiate price 

premiums. 

Most product prices are as of July 2005. 

** The Climate Neutral Network certifies the methodology used to calculate the CO2 emissions offset. 

NA = Not applicable. 

 136
3.9 – Federal Agency Purchases of Green Power 

The federal government exceeded its goal of obtaining 2.5% of its electricity needs from 

renewable energy sources by September 30, 2005. The federal renewable energy goal 

was established under Executive Order 13123, issued by President Clinton in 1999. The 

federal government, which is the nation's largest energy consumer, purchases 2.375 

billion kWh of renewable energy annually.

The Energy Policy Act of 2005, signed into law by President Bush on August 8, 2005, 

establishes a new set of federal renewable energy goals, calling for agencies to derive 3%

of their electric energy from renewable sources in fiscal years 2007 through 2009, 

increasing to 5% in fiscal years 2010 through 2012, and 7.5% by 2013 and each fiscal 

year thereafter.

 137
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). 

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; SRP – Earthwise Solar 

Energy; TEP – SunShare PV Buydown; UES – 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; 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; IID Energy – PV 

Solutions Rebate Program; LADWP – Solar Incentive Program; 

Pasadena Water and Power – Solar Power Installation Rebate; 

Redding Electric – Earth Vantage Renewable Energy Rebate

Program; Riverside Public Utilities – Energy Efficiency Construction 

Incentive; Riverside Public Utilities – Residential Photovoltaic

Incentive Program; Roseville Electric – PV Buy Down Program; 

SMUD Commercial/Industrial PV Rebate; SMUD – PV Pioneers 

Residential Buy-Down; SMUD – Solar Water Heater Program

Rebate; Ukiah Utilities – PV Buy-Down Program 

Marin County – Solar Rebate Program; San Diego – Residential

Solar Electric Incentive for Homes Destroyed in Wildfires 

Santa Monica – Green Building Grant Program; SMUD – Solar 

Water Heater Loan Program; 

Supplemental Energy Payments (SEPs) 

CO Utility PV Rebate; Holy Cross Energy WE CARE Rebates 

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 

CT Local Option for Property Tax Residential Solar PV Rebate Program; Connecticut - Commercial,

Industrial, Institutional PV Grant Program; Connecticut - New

Energy Technology Program; Energy Conservation Loan; 

Operational Demonstration Program; Renewable Energy Projects in 

Pre-Development Program

DE Green Energy Program Rebates; Research and Development 

Grants; Technology and Demonstration Grants 

DC District of Columbia Renewable Demonstration Project 

FL Solar Energy Equipment 

Exemption 

Florida - Gainesville Regional Utilities - Solar Rebate Program; 

Florida - JEA - Solar Incentive Program 

GA 

 138
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; 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) 

Renewable Energy Equipment Sales Tax Refund; BEF - Renewable 

Energy Grant; BEF – Solar 4R Schools; Low-Interest Loans for 

Renewable Energy Resource Program 

IL Special Assessment for

Renewable Energy Systems 

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 Renewable Energy Production

Tax Credit (Personal); Renewable 

Energy Production Tax Credit 

(Corporate); 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 Solar Water Heater Loan Program 

LA Solar Energy System Exemption 

ME Solar Rebate Program; Renewable Resources Matching Fund 

Program 

MD Personal Income Tax Credit for 

Green Buildings; Corporate 

Income Tax Credit for Green 

Buildings; 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; Montgomery County – Clean Energy

Rewards Program

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 

Commercial, Industrial, & Institutional Initiative Grants; Small 

Renewables Initiative Rebate; Matching Grants for Communities 

MI Alternative – Energy Personal 

Property Tax Exemption; 

Community Energy Project Grants; Energy Efficiency Grants; LargeScale PV Demonstration Project Grants; Michigan Biomass Energy

Program Grants; Solar Domestic Hot Water System Rebate 

Program; Small Business P2 Loan Program 

MN Solar-Electric (PV) Sales Tax

Exemption; Wind Sales Tax

Exemption; Wind and SolarState of Minnesota Solar-Electric (PV) Rebate Program; Great River 

Energy - Solar-Electric (PV) Rebate Program; Minnesota Power 

Solar-Electric (PV) Rebate Program; Renewable Development Fund

 139
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

Electric (PV) Systems Exemption Grants; Agricultural Improvement Loan Program for Wind Energy; 

Energy Investment Loan Program; Value-Added Stock Loan 

Participation Program

Renewable Energy Production Incentives 

MS Energy Investment Loan 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 - USB Renewable Energy Fund; BEF -

Renewable Energy Grant; BEF – Solar 4R Schools; Alternative 

Energy Revolving Loan Program

NE Dollar and Energy Savings Loans 

NV Renewable Energy/Solar Sales 

Tax Exemption; Property Tax

Abatement for Green Buildings; 

Renewable Energy Producers

Property Tax Abatement; 

Renewable Energy Systems 

Property Tax Exemption 

Solar Generations PV Rebate Program 

NH Local Option Property Tax

Exemption for Renewable Energy

NJ Solar and Wind Energy Systems 

Exemption 

New Jersey Clean Energy Rebate Program; Renewable Energy

Advanced Power Program; Renewable Energy Economic

Development Program (REED); Renewable Energy Business

Venture Assistance Program (REBVAP); Clean Energy Financing 

for Local Schools and Governments 

NM Renewable Energy Production

Tax Credit; Biomass Equipment 

and Materials Deduction; 

Clean Energy Grants Program; Schools with Sol 

NY Solar and Fuel Cell Tax Credit; 

Solar Cells Tax Exemption; Solar, 

Wind and Biomass 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 (EILP) 

ND Geothermal, Solar and Wind 

Personal Credit; Geothermal,

Solar, and Wind Corporate Credit; 

Hydrogen and 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

Exemption 

Residential Renewable Energy Grants; Renewable Energy Loans 

 140
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

OK Zero-Emission Facilities

Production Tax Credit 

OR Residential Energy Tax Credit; 

Business Energy Tax Credit; 

Renewable Energy Systems 

Exemption 

Energy Trust Solar Electric Buy-Down Program; Energy Trust Solar 

Water Heating Buy-Down 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; Energy

Trust Open Solicitation Program; BEF - Renewable Energy Grant; 

BEF – Solar 4R Schools; 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

RI Residential Renewable Energy

Tax Credit; Renewable Energy

Sales Tax Exemption; Solar 

Property Tax Exemption 

PV & Wind Rebate Program; Small Customer Incentive Program for 

Green Power Marketers; RFP for Purchase/Sale of Renewable 

Electricity to Large Customers

Renewable Generation Supply Incentive 

SC Residential Solar Initiative for EarthCraft Homes Rebate 

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; Renewable

Energy Systems Property Tax

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 & Small Wind Incentive Program; CVPS Biomass Grants

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; Clark Public Utilities

– Solar Water Heater Rebate Program; Grays Harbor PUD - Solar 

Water Heating Rebate; Klickitat PUD – Solar Rebate; Orcas Power 

& Light - Photovoltaic Rebate; Puget Sound Energy - Solar PV

System Rebate; Franklin PUD – Photovoltaic and Solar Water 

Heating Rebate; 

WV Tax Exemption for Wind Energy

Generation; Special Assessment 

for Wind Energy Systems 

 141
State Tax Incentives Grants, Loans, Rebates and Other Incentives 

WI Solar and Wind Energy

Equipment Exemption 

Focus on Energy - Cash-Back Reward; Wisconsin Public Power, 

Inc. – Residential Renewable Energy Rebate; Focus on Energy - 

Grant Programs; Focus on Energy – Zero-Interest Loans; Wisconsin 

Public Power, Inc. – Residential Renewable Energy Loan 

WY Renewable Energy Sales Tax

Exemption 

Photovoltaic Incentive Program

Source: North Carolina Solar Center, Database of State Incentives for Renewable Energy,

http://www.dsireusa.org/summarytables/financial.cfm?&CurrentPageID=7, November 2005.

 142
Table 4.1 – Projections of Renewable Electricity Net Capacity

(Gigawatts) 

Data Sources Projections 

Renewable Energy 2006 2010 2015 2020 2025 2030 

Geothermal AEO2006 - Reference Case 2.23 2.56 3.19 4.61 6.02 6.64 

AEO2006 - High Renewables 2.80 6.19 9.14 

EERE GPRA FY07 2.21 2.61 3.53 4.88 

Wind AEO2006 - Reference Case 11.56 16.27 17.71 18.81 19.80 20.10 

AEO2006 - High Renewables 16.27 18.87 22.63 

EERE GPRA FY07 8.91 18.98 77.66 135.85 

Solar1 AEO2006 - Reference Case 0.67 1.17 1.31 1.47 1.71 2.62 

AEO2006 - High Renewables 1.17 1.47 2.87 

EERE GPRA FY07 1.97 6.27 31.16 68.86 

Hydroelectric AEO2006 - Reference Case 78.31 78.32 78.37 78.53 78.53 78.53 

AEO2006 - High Renewables 78.33 78.41 78.76 

EERE GPRA FY07 79.21 79.21 79.21 79.21 

Biomass/Wood 

(excludes cogen) AEO2006 - Reference Case 2.09 2.15 2.15 2.46 3.45 4.63 

AEO2006 - High Renewables 2.20 3.96 10.55 

EERE GPRA FY07 1.83 2.01 2.62 4.57 

MSW and LFG AEO2006 - Reference Case 3.55 3.78 3.92 4.02 4.11 4.14 

AEO2006 - High Renewables 3.79 4.03 4.14 

EERE GPRA FY072 3.83 3.84 3.92 3.93 

Total Renewable Energy AEO2006 - Reference Case 102.92 109.26 112.12 115.93 120.21 123.95 

AEO2006 - High Renewables 109.82 119.81 137.09 

EERE GPRA FY073 98.54 115.53 196.25 225.38 

Sources: EIA Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Tables 

A16 and D7. Total Renewable Capacity GPRA projections provided by OnLocation, February 2006. 

Notes: OnLocation GPRA07 benefits estimates do not estimate any programmatic influence on biomass power, 

because 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. The GPRA FY07 

modeling effort uses the NEMS model, which uses the EIA AEO 2005 as the baseline for its analysis. 

1 Solar-thermal and photovoltaic energy. 

2

 EERE does not have an R&D program for biomass, LFG/MSW, so they 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. 

143
Table 4.2 – Projections of Renewable Electricity Net Generation 

(Billion Kilowatthours) 

Renewable Energy 

Geothermal 

Data Sources 

AEO2006 - Reference Case 

2006 

14.91 

2010 

17.51 

Projections 

2015 2020 

22.84 34.01 

2025 

46.74 

2030 

52.70 

AEO2006 - High Renewables 

EERE GPRA FY07 

19.16 

12.30 15.60 

47.91 

23.50 35.00 

73.01 

Wind AEO2006 - Reference Case 35.25 50.87 55.98 59.82 63.48 64.51 

AEO2006 - High Renewables 50.87 59.97 73.90 

EERE GPRA FY07 25.80 64.60 309.40 558.60 

Solar1 AEO2006 - Reference Case 1.19 2.35 2.69 3.10 3.68 5.71 

AEO2006 - High Renewables 2.36 3.10 6.25 

EERE GPRA FY07 3.90 12.80 63.10 151.10 

Hydroelectric AEO2006 - Reference Case 293.13 301.40 301.82 302.87 303.06 303.27 

AEO2006 - High Renewables 301.40 302.15 304.46 

EERE GPRA FY07 303.60 303.70 304.00 304.30 

Biomass/Wood (without 

cogeneration) AEO2006 - Reference Case 18.87 44.67 44.80 48.59 51.30 57.83 

AEO2006 - High Renewables 45.45 59.94 95.96 

EERE GPRA FY07 27.20 29.60 32.10 39.30 

MSW and LFG AEO2006 - Reference Case 25.29 27.13 28.20 29.06 29.75 30.03 

AEO2006 - High Renewables 27.13 29.08 30.04 

EERE GPRA FY072 27.70 27.80 28.50 28.60 

Total Renewable Energy AEO2006 - Reference Case 417.45 475.75 490.86 515.15 539.06 559.14 

AEO2006 - High Renewables 479.65 544.91 638.67 

EERE GPRA FY073 400.70 454.70 742.60 927.90 

Sources: EIA Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Tables 

A16 and D7. Renewable generation GPRA projections provided by OnLocation, February 2006. 

Notes: OnLocation GPRA07 benefits estimates do not estimate any programmatic influence on biomass power, 

because 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. The GPRA FY07 

modeling effort uses the NEMS model, which uses the EIA AEO 2005 as the baseline for its analysis. 

1 Solar-thermal and photovoltaic energy. 

2

 EERE does not have an R&D program for biomass, LFG/MSW, so they 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. 

144
Table 4.3 – Projections of Renewable Electricity Carbon Dioxide 

Emissions Savings 

(Million Metric Tons Carbon Equivalent per Year) 

Data Sources Projections 

2006 2010 2015 2020 2025 2030 

Renewable Energy 

Geothermal AEO2006 - Reference Case 2.87 3.48 4.22 5.59 7.17 6.88 

AEO2006 - High Renewables 3.81 7.87 9.53 

EERE GPRA FY07 2.44 2.88 3.86 5.37 

Wind AEO2006 - Reference Case 6.79 10.10 10.34 9.83 9.74 8.42 

AEO2006 - High Renewables 10.10 9.85 9.65 

EERE GPRA FY07 5.12 11.93 50.84 85.69 

Solar1 AEO2006 - Reference Case 0.23 0.47 0.50 0.51 0.56 0.75 

AEO2006 - High Renewables 0.47 0.51 0.82 

EERE GPRA FY07 0.77 2.36 10.37 23.18 

Hydroelectric AEO2006 - Reference Case 56.43 59.86 55.75 49.77 46.49 39.60 

AEO2006 - High Renewables 59.86 49.65 39.75 

EERE GPRA FY07 60.30 56.10 49.96 46.68 

Biomass/Wood AEO2006 - Reference Case 3.63 8.87 8.27 7.98 7.87 7.55 

AEO2006 - High Renewables 9.03 9.85 12.53 

EERE GPRA FY07 5.40 5.47 5.27 6.03 

MSW and LFG AEO2006 - Reference Case 4.87 5.39 5.21 4.78 4.56 3.92 

AEO2006 - High Renewables 5.39 4.78 3.92 

EERE GPRA FY072 5.50 5.13 4.68 4.39 

Total Renewable Energy AEO2006 - Reference Case 80.36 94.49 90.67 84.65 82.69 73.00 

AEO2006 - High Renewables 95.27 89.54 83.39 

EERE GPRA FY073 79.59 83.99 122.03 142.34 

Heat Rate Btu/kWh 10,796 10,593 9,019 8,266 7,891 6,872

Carbon Coefficient MMTCE/Tbtu 0.01783 0.01875 0.02048 0.01988 0.01944 0.01900

Sources: Generation data: EIA Annual Energy Outlook 2006, DOE/EIA-0383 (06) (Washington, D.C., 

February 2006), Tables A16 and F8. Renewable generation GPRA projections provided by OnLocation, 

February 2006. Heat Rate and Carbon Coefficienct data based on GPRA 2003 Data Call. 

Carbon emission coefficients and heat rates for 2006-2025: U.S. Department of Energy, GPRA2003 Data 

Call, Appendix B, pages B-13 and B-16, (September 14, 2001). 2030 values are NREL estimates based on 

trend. 

145
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, so they 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. 

146
Table 5.1 – U.S. Total and Delivered Energy (Overview) 

(Quadrillion Btu per year) 

1980 1990 2000 2001 2002 2003 2004 7 2010 2015 20

Total Consumption by Source 1 

Petroleum 2 34.20 33.55 38.26 38.19 38.23 38.81 39.83 43.14 45.69 48

Natural Gas 20.39 19.74 23.91 22.90 23.62 23.07 22.98 24.04 26.67 27Coal3 15.39 19.58 23.54 22.91 23.10 23.48 23.66 25.09 25.66 27Nuclear 2.74 6.10 7.86 8.03 8.14 7.96 8.23 8.44 8.66 9

Renewable4 5.49 6.13 6.16 5.33 5.84 6.08 6.12 7.08 7.43 8

Other 5 0.07 -0.03 0.06 -0.02 -0.01 -0.07 0.04 0.07 0.08 0Total Primary 78.29 84.71 98.96 96.47 97.87 98.31 99.73 107.87 114.18 120

Total Consumption by Sector Residential 15.85 17.06 20.53 20.29 20.91 21.20 21.18 22.99 24.07 25

Commercial 10.59 13.32 17.18 17.37 17.58 17.45 17.51 19.51 21.23 23

Industrial 32.15 31.90 34.70 32.53 32.53 32.56 33.25 34.46 35.60 36

Transportation 19.70 22.42 26.55 26.28 26.85 27.10 27.79 30.90 33.29 35

Total Primary6 78.29 84.71 98.96 96.47 97.87 98.31 99.73 107.87 114.18 120

Delivered Consumption by Sector Residential 7.50 6.60 7.20 6.91 6.89 7.19 7.02 12.25 12.81 13

Commercial 4.10 3.85 4.22 4.04 4.10 4.26 4.07 9.00 9.85 10

Industrial 22.67 21.21 22.80 21.80 21.77 21.48 22.08 26.67 27.72 28

Transportation 19.66 22.37 26.49 26.22 26.79 27.03 27.71 30.70 33.09 35Total Delivered6 53.93 54.03 60.72 58.96 59.54 59.95 60.88 78.62 83.46 88

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Tables A1 and A2; 

EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), 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 nonpetroleum-based liquids for blending, such as ethano3 Includes coal in all sectors, as well as net imports of coal coke in the industrial sector. 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

residential heating; and both the ethanol and gasoline components of E85 (which, due to seasonal adjustments in mix, is E74, 

lower percentage blends of ethanol (e.g. E10). Excludes electricity imports using renewable sources and nonmarketed renewa
7

5 For historical figures, this value includes hydroelectric pumped storage and electricity net imports – except in 2004, where it o

net imports (AER 2004 no longer includes hydroelectric pumped storage). For forecasted figures, this value includes net elect

and liquid hydrogen. 

6 For historical figures, this value does not include the electric-power sector's consumption. 

 All 2004 figures are preliminary. 
Table 5.2 – Electricity Flow Diagram (Quadrillion Btu) 

Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Diagram 5. Notes: a Blast furnace gas, propane gas, and other manufactured e Electric energy used in the operation of power plants, estimated and waste gases derived from fossil fuels. generation. b Batteries, chemicals, hydrogen, pitch, purchased steam, f Transmission and distribution losses (electricity losses that occusulfur and miscellaneous technologies. point of generation and delivery to the customer) are estimated a

generation. 
c Estimated as net generation divided by 0.95. g Use of electricity that is 1) self-generated, 2) produced by eithe

that consumes the power or an affiliate, and 3) used in direct supindustrial process located within the same facility or group of facilgenerating equipment. Direct use is exclusive of station use. 

d Data collection frame differences and sampling error.

Totals may not equal sum of components, due to independent rounding. 
Table 5.3 – Electricity Overview

(Billion Kilowatthours, unless otherwise noted) 

1980 1990 2000 2001 2002 2003 2004 7 2010 2015 2020 

Electric-Power Sector Generation1 2,286 2,901 3,638 3,580 3,698 3,721 3,794 4,196 4,501 4,827 

End-Use Sector Generation 3 137 164 157 160 162 160 192 226 280 Total Generation 2,290 3,038 3,802 3,737 3,858 3,883 3,953 4,388 4,727 5,108 Capability (gigawatts) Electric-Power Sector2 579 710 782 819 876 919 938 988 965 1,027 

 End-Use Sector3 NA 24 30 29 29 30 30 32 37 44 

 Total Capability 579 734 812 848 905 949 968 1,021 1,002 1,072 

Imports from Canada/Mexico 25 18 49 39 36 30 34 42 41 29 Exports to Canada/Mexico 4 16 15 16 14 24 22 21 18 15 Loss and Unaccounted for4 216 203 243 226 253 233 248 NA NA NA 

Retail Sales 5 2,094 2,713 3,421 3,370 3,463 3,488 3,551 3,978 4,300 4,629 

Direct Use 6 NA 125 171 163 166 168 166 177 192 214 

Total Use 2,094 2,838 3,592 3,533 3,629 3,656 3,717 4,155 4,491 4,844 

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2005), Tables A8, A9, and A1

Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), 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 e

electricity and heat – to the public.Through 1988, data are for electric utilities only; beginning in 1989, data are for electric utiliti

independent power producers. 2 Through 1988, data are for net summer capacity at electric utilities only. Beginning in 1989, data also include net summer cap

independent power producers. All data after 1989 include electric-sector combined-heat-and-power (CHP) plants. 3 Commercial and industrial combined-heat-and-power (CHP) and electricity-only plants; and small on-site generating systems 

commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to the grid. Data 

4 Electricity losses that occur between the point of generation and delivery to the customer, and data collection frame differenc

nonsampling error. 5 Electricity retail sales to ultimate customers reported by electric utilities and other energy-service providers. 6 Commercial and industrial facility use of on-site net electricity generation; and electricity sales among adjacent or colocated f

revenue information is not available. 

NA = not available 
Table 5.4 – Consumption of Fossil Fuels by Electric Generators 

1980 1990 2000 2001 2002 2003 2004 8 2010 2015 2020 2025 

Coal (million short tons) 1 569 781 983 962 975 1,003 1,013 1,140 1,161 1,235 1,354 

Distillate Fuel Oil (million barrels) 2 29 16 30 29 22 27 18 40 40 41 44 

Residual Fuel Oil (million barrels) 3 391 183 138 159 105 137 141 117 116 117 118 

Petroleum Coke (million short tons) 0.2 1.0 3.2 3.3 5.7 5.7 6.8 NA NA NA NA Other Liquids (million barrels) 4 NA 0.02 0.4 0.4 1.2 1.9 2.0 NA NA NA NA 

Total Petroleum (million barrels) 5 421 205 184 205 156 195 195 157 156 158 162 

Natural Gas (billion cubic feet) 3,682 3,147 5,014 5,142 5,408 4,909 5,217 5,509 7,142 7,459 7,052 Stocks of Coal and Petroleum (end of year) 6 

Coal (million short tons) 183 156 102 138 142 122 107 NA NA NA NA Petroleum (million barrels) 7 136 84 41 57 52 53 50 NA NA NA NA 

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Tables A2, A13, and AAnnual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.5b and 8.8. Notes: Data is for electric-power sector consumption only. Data include fuel consumption to produce electricity by combined-heat-and

plants. Through 1988, consumption data are for electric utilities only. Beginning in 1989, consumption data also include independent power producers. 

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 1

2000, electric utility data also include small amounts of kerosene and jet fuel. Forecast values calculated from quadrillion Btu u

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 a

include a small amount of fuel oil No. 4. Forecast values calculated from quadrillion Btu using conversion factor 6.287 MMBtu/b

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 calculated sum.

6 Through 1998, data are for electric utilities only. Beginning in 1999, data are for electric utilities and independent power produ7 Includes distillate fuel oil, residual fuel oil, other liquids, and petroleum coke. 8 All 2004 figures are preliminary

NA = not available 
Table 5.5 – Electric-Power Sector Energy Consumption 

(Trillion Btu) 

1980 1990 2000 2001 2002 2003 2004 5 

Coal 12,123 16,235 20,185 19,494 19,733 20,137 20,227 

Natural Gas 3,810 3,224 5,120 5,271 5,522 5,009 5,351 Petroleum 2,634 1,281 1,145 1,270 955 1,199 1,196 Other Gas 1 NA 6 19 9 25 30 30 

Total Fossil Fuels 18,567 20,746 26,470 26,044 26,235 26,374 26,804 Nuclear Electric Power 2,739 6,104 7,862 8,033 8,143 7,959 8,232 Hydroelectric Pumped Storage 2 --- -36 -57 -90 -88 -88 -- 6 

Conventional Hydroelectric 2,867 3,014 2,768 2,209 2,650 2,781 2,673 Wood 3 106 126 116 141 156 158 

Waste 2 180 294 314 353 337 334 

Geothermal 110 326 296 289 305 303 302 Solar 3 NA 4 5 6 6 5 6 

Wind NA 29 57 70 105 115 143 

Total Renewable Energy 2,982 3,658 3,547 3,003 3,560 3,697 3,616 Electricity Imports 71 8 115 75 78 22 39 Other 4 NA 0.08 1.28 0.00 6.96 15.57 0.09 

Total Primary Consumption 24,359 30,517 37,995 37,154 38,022 38,068 38,692 

2010 2015 202

22,919 23,352 25,01

5,647 7,320 7,64

971 960 97

NA NA N

29,537 31,633 33,63

8,442 8,659 9,08

NA NA N

2,983 2,985 2,99

518 522 56335 349 36393 567 91

10 13 1

524 577 61

4,763 5,013 5,47

74 79 4

NA NA N

42,817 45,383 48,24

Sources: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.4b; and EIA, Ann2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), 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 198

consumption at electric utilities only. Beginning in 1989, data also include consumption at independent power producers. 

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. 5 All 2004 figures are preliminary
6 Starting with AER 2004 (August 2005), energy consumed by hydroelectric pumped storage plants is no longer included. Acco

change was made because most of the electricity used to pump water into elevated storage reservoirs is generated by plants ostorage plants; thus, the associated energy is already accounted for in other data columns in the tables (such as conventional coal, and natural gas). The data book has kept historical record of pumped storage hydroelectric pumped storage plants, becais useful to some analysts. 

NA = not available 
Table 5.6 – Fossil-Fuel Generation by Age of Generating Units 

(Megawatts) 

1980 1990 1999 2000 2001 2002 2003 2004 2005 

0-5 

6-10 

11-20 

21-30 

31-40 

41-50 

>50 

Total: 

91,001 

136,236 

145,618 

99,223 

21,042 

4,023 

4,232 

501,376 

39,870 

54,270 

224,879 

143,868 

93,450 

14,701 

2,566 

573,603 

34,466 

42,215 

102,855 

226,166 

128,613 

80,859 

8,291 

623,465 

54,274 

44,042 

92,854 

221,690 

141,055 

86,582 

11,634 

652,129 

90,877 

42,164 

87,057 

210,982 

155,292 

91,321 

15,259 

692,952 

155,534 

37,735 

82,977 

196,464 

172,139 

94,204 

18,161 

757,214 

204,504 

33,121 

83,140 

175,461 

188,274 

95,560 

24,487 

804,546 

218,854 

33,234 

81,085 

156,694 

205,136 

93,156 

33,967 

822,128 

233,119 

33,976 

81,465 

156,078 

204,382 

89,731 

31,676 

830,427 

Source: PowerDat, © 2005, Platts, a division of the McGraw-Hill companies. 

Notes: 

Total MW does not equal fossil-fuel generation capacity cited in Table 6.1. 

Capacity reported in this table is nameplate capacity. 
Table 5.7 – Nuclear Generation by Age of Generating Units 

(Megawatts) 

1980 1990 1999 2000 2001 2002 2003 2004 2005 

0-5 16,289 30,408 1,270 1,270 0 0 0 0 0 

6-10 33,989 25,628 4,810 1,215 2,485 2,485 1,270 1,270 1,270 

11-20 6,413 48,929 54,432 56,036 51,537 49,189 47,200 40,278 31,435 

21-30 309 6,073 44,558 44,597 46,859 43,105 41,420 39,315 40,533 

31-40 0 0 2,143 4,095 6,332 12,435 17,324 26,351 32,940 

Total 57,000 111,039 107,214 107,214 107,214 107,214 107,214 107,214 106,177 

Source: PowerDat, © 2005, Platts, a division of the McGraw-Hill companies. 

Notes: 

Total MW does not equal nuclear-generation capacity cited in Table 6.1. 

Capacity reported in this table is nameplate capacity. 
Table 5.8 – Operational Renewable Energy Generating Capacity 

(Megawatts) 

1980 1990 2000 2001 2002 2003 1 

Agricultural Residues2 40 165 373 373 373 373 

BioGas3 18 361 933 999 1,030 1,053 Municipal Solid Waste4 263 2,172 2,970 2,970 2,970 3,000 

Timber Residues5 3,576 6,305 7,447 7,458 7,497 7,497 

Bioenergy Total 6 3,897 9,003 11,722 11,800 11,869 11,922 Geothermal 802 2,540 2,779 2,779 2,779 2,779 

Photovoltaic 7 0.025 4.170 27.645 38.452 59.703 67.710 

Solar Thermal 0 274 354 354 354 354 Hydro 8 80,491 90,955 94,324 94,335 94,335 94,356 

Wind 0.06 1,569 2,780 4,623 5,078 5,090 

Total 85,190 104,344 111,987 113,930 114,475 114,569 Source: Renewable Electric Plant Information System (REPiS Database), Version 7, National Renewable Energy Laborathttp://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 shells3Biogas, 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 o

8 There are an additional 24 MW of hydroelectric capacity that are not accounted for here, because they have no specific o
Table 5.9 – Number of Utilities by Class of Ownership and Nonutilities 

1980 1990 1999 2000 2001 2002 2003 200

Investor-Owned Utilities 240 266 238 240 232 230 223 22Federally Owned Utilities 41 10 9 9 9 9 9 Cooperatively Owned Utilities1 936 951 901 894 889 882 885 88

Other Publicly Owned Utilities 1,753 2,010 2,012 2,013 2,015 2,012 2,015 2,0Total Number of Utilities 2,970 3,237 3,160 3,156 3,145 3,120 3,154 3,15Nonutilities NA NA 381 446 1,380 1,500 1,538 1,15Power Marketers NA NA 155 134 127 136 147 15Sources: EIA, The Changing Structure of the Electric Power Industry 2000: An Update (historical); EIA 8

report (1999+ for utilities) - http://www.eia.doe.gov/cneaf/electricity/page/eia861.html; and Form EIA-906 EIA-920 databases (2001+ for IPPs) - http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html Notes: 

1 Co-ops operate in all states except Connecticut, Hawaii, Rhode Island, and the District of Columbia 

NA = not available 1999 and 2000 for nonutilities exclude commercial and industrial generators, while 2001-2004 include commercial and industrial generators. 
Table 5.10 – Top 10 U.S. Investor-Owned Utilities & Power Marketers 

1990 2000 2001 2002 200

Utility by Sales (Million kWh) Rank Million kWh Rank Million kWh Rank Million kWh Rank Million kWh Rank Mi

Florida Power & Light Co. 5 65,222 2 88,128 2 90,495 1 95,543 1 

Georgia Power Co. 8 53,953 4 74,434 5 72,545 3 75,432 3 

Duke Energy Corp 7 58,359 9 53,726 4 72,977 4 75,362 4 

Virginia Electric & Power Co. 9 52,122 8 65,294 7 67,858 6 71,477 5 

TXU Electric Co.1 1 78,340 1 100,885 1 102,526 2 90,522 2 

Commonwealth Edison Co. 2 70,852 3 77,176 3 76,918 5 73,835 6 

Alabama Power Co. 12 38,081 10 52,068 9 49,338 8 52,073 8 

Pacific Gas & Electric Co. 3 70,597 7 72,121 12 46,680 9 49,830 10 

Southern California Edison Co. 4 70,063 6 73,686 8 52,034 7 54,391 7 

PacifiCorp 10 40,288 43 18,859 11 47,708 1 In 2002, electric industry restructuring commenced in Texas and both TXU and Reliant became Power Marketers 11 47,030 9 

1990 2000 2001 2002 200

Utility by Revenue (Million $) Rank Million $ Rank Million $ Rank Rank Million $ Rank M

Florida Power & Light Co. 4 4,803 4 6,065 3 7,302 2 7,028 1 

Pacific Gas & Electric Co. 2 6,513 2 6,988 4 7,171 3 6,821 4 

TXU Electric Co.1 6 4,200 3 6,433 2 7,748 4 6,520 3 

Southern California Edison Co. 1 6,767 1 7,416 1 7,782 1 7,848 2 

Consolidated Edison Co-NY Inc 5 4,385 6 5,286 6 5,622 6 4,874 5 

Commonwealth Edison Co. 3 5,668 5 5,723 5 5,703 5 5,457 6 

Virginia Electric & Power Co. 10 3,299 9 4,022 7 4,340 7 4,611 7 

Georgia Power Co. 9 3,426 8 4,283 8 4,305 9 4,288 9 

Duke Energy Corp 7 3,681 12 3,151 9 4,159 8 4,345 8 

Reliant Energy HL&P1 8 3,436 7 4,743 10 5,622 14 2,898 11 

1 In 2002, electric industry restructuring commenced in Texas and both TXU and Reliant became Power Marketers 

Source: EIA, Electric Sales and Revenue , DOE/EIA -0540 (00) (Washington, D.C., December 2005), Table 10 (2005) and Table 17 (p
Table 5.11 – Top 10 Independent Power Producers Worldwide 

(Megawatts) Company SUEZ Energy International (formerly Tractebel Electricity & Gas Int'l) AES ENEL SpA. Calpine Dominion Generation Entergy Wholesale Operations Reliant Mirant NRG Energy Edison Mission Energy1 

2002 Capacity (MW) 

50,000 

55,660 

46,456 

19,319 23,830 

21,323 

22,349 

22,100 

20,954 

18,688 

2003 Capacity (MW) 

48,317 

44,917 

45,744 

29,891 

24,408 

30,000 

19,442 

23,254 

21,200 

18,733 

2004 

1 In 2004, Edison Mission Energy sold most of its international power-generating assets. 

Source: Company 10K SEC filings at http://www.sec.gov/ accessed 2/06 
Table 5.12 – Utility Mergers and Acquisitions 

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 

Mergers/Acquisitions IOU-IO U 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 1 5 4 3 6 1 

Muni-Muni 1 2 Muni-Co-op 1 1 Power Authority-IOU 1 Nonutility-IOU 6 1 

Nonutility-Muni TransCo-IOU T assets Foreign-IOU 2 2 1 3 

Total 8 4 4 4 16 6 2 9 4 25 30 26 27 11 Related Activities Name Changes 5 2 7 11 1 4 New Holding Company 1 5 4 2 3 

Moved Headquarters 1 Ceased Operations 1 

Source: Calculated from Electrical World, Directory of Electric Power Producers, 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 3 Includes pending mergers and acquisitions 
Table 5.13a – North American Electric Reliability Council Map for the United Sta

ECAR ECAR East Central Area Reliability NPCC

Coordination Agreement 

Northeast Power Coordinating Counci

ERCOT Electric Reliability Council of Texas SERC Southeastern Electric Reliability CouncFRCC Florida Reliability Coordinating Council SPP Southwest Power Pool MAAC Mid-Atlantic Area Council WECC Western Electricity Coordinating CounMAIN Mid-Atlantic Interconnected Network ASCC Alaskan Systems Coordinating CouncMAPP Mid-Continent Area Power Pool Source: North American Electric Reliability Council, www.nerc.com 
Table 5.13b – Census Regions 

 Source: U.S. Department of Commerce, Bureau of the Census, www.census.gov 

Table 6.1 – Electric Net Summer Capability (All Sectors) 

(Gigawatts) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 

 Coal1 NA 307.4 315.1 314.2 315.4 313.0 313.3 322.8 325.5 

 Petroleum/Natural Gas2 NA 220.4 283.8 320.7 374.2 418.2 436.9 466.1 437.9 Total Fossil Energy 444.1 527.8 598.9 634.9 689.5 731.2 750.2 788.9 763.4 Nuclear 51.8 99.6 97.9 98.2 98.7 99.2 99.6 100.9 104.0  Hydroelectric Pumped Storage3 NA 19.5 19.5 19.1 20.4 20.5 20.5 20.8 20.8  Conventional Hydroelectric 81.7 73.9 79.4 79.5 79.4 78.7 78.7 78.3 78.4  Geothermal 0.9 2.7 2.8 2.2 2.3 2.1 2.1 2.6 3.2 

Wood 4 0.1 5.5 6.1 5.9 5.8 5.9 5.9 7.2 7.6 

Waste 5 NA 2.5 3.9 3.8 3.8 3.8 3.8 3.8 3.9 

 Solar Thermal and Photovoltaic NA 0.3 0.4 0.4 0.4 0.4 0.4 1.2 1.3 

Wind NA 1.8 2.4 3.9 4.4 6.0 6.2 16.3 17.7 

Total Renewable Energy 82.7 86.8 94.9 95.7 96.1 96.9 97.1 109.3 112.1 Other 6 NA 0.5 0.5 0.4 0.6 0.6 0.6 0.7 0.7 Total Electric Capability 578.6 734.1 811.7 848.3 905.3 948.4 968.1 1020.6 1001.1 Sources: EIA, Annual Energy Outlook 2006 DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Tables A9, A16; EIA, 

2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.11a. Notes: Data include electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity – or elecpublic. Through 1988, data are for net summer capacity at electric utilities only. Beginning in 1989, data also include net summpower 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 
Table 6.2 – Electricity-Only Plant Net Summer Capability 

(Gigawatts) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 

 Coal 2 NA 299.9 305.2 305.2 305.8 303.0 303.4 313.7 315.0 

 Petroleum/Natural Gas 3 NA 198.7 243.9 279.4 325.1 362.9 378.9 409.4 379.1 Total Fossil Energy NA 498.6 549.0 584.5 630.9 665.9 682.2 723.1 694.1 Nuclear NA 99.6 97.9 98.2 98.7 99.2 99.6 100.9 104.0 Hydroelectric Pumped Storage 4 NA 19.5 19.5 19.1 20.4 20.5 20.5 20.8 20.8  Conventional Hydroelectric NA 73.3 78.2 78.4 78.3 77.9 77.9 77.7 77.8  Geothermal NA 2.7 2.8 2.2 2.3 2.1 2.1 2.6 3.2 

Wood 5 NA 1.0 1.5 1.5 1.4 1.4 1.4 2.2 2.2 

Waste 6 NA 1.9 2.8 3.0 3.0 2.8 2.9 3.5 3.7 

 Solar Thermal and Photovoltaic NA 0.3 0.4 0.4 0.4 0.4 0.4 0.5 0.6 

Wind NA 1.8 2.4 3.6 4.4 6.0 6.0 16.3 17.7 

Total Renewable Energy NA 80.9 88.1 89.1 89.7 90.6 90.7 102.7 105.1 Other NA 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Electric Capability 7 NA 698.6 754.5 790.8 839.2 876.3 893.1 947.5 924.0 Sources: EIA, Annual Energy Outlook 2006 DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Tables A9, A16; E2003, 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. Tnet summer capacity at electric utilities only. Beginning in 1989, data also include net summer capacity at independent po

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-f

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 
Table 6.3 – Combined-Heat-and-Power Plant Net Summer Capability 

(Gigawatts) 

1980 1990 2000 2001 2002 2003 2004 2010 201

 Coal 2 NA 7.5 10.0 9.1 9.5 10.0 9.9 9.1 10.

 Petroleum/Natural Gas 3 NA 21.7 39.9 41.3 49.1 55.3 58.0 56.7 58.Total Fossil Energy NA 29.2 49.9 50.4 58.6 65.3 67.9 65.8 69.Nuclear NA 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.

Hydroelectric Pumped Storage NA 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0. Conventional Hydroelectric NA 0.6 1.1 1.1 1.1 0.8 0.8 0.7 0. Geothermal NA 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.

Wood 4 NA 4.6 4.9 4.6 4.7 4.7 4.8 5.0 5.

Waste 5 NA 0.4 0.6 0.5 0.5 0.5 0.5 0.3 0.

 Solar Thermal and Photovoltaic NA 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.

Wind NA 0.0 0.0 0.3 0.0 0.0 0.0 0.0 0.

Total Renewable Energy NA 5.3 6.1 5.8 5.8 5.6 5.6 7.0 7.Other NA 0.5 0.5 0.4 0.6 0.6 0.6 0.7 0.Total Electric Capability 6 NA 35.5 57.2 57.4 65.6 72.1 75.0 73.4 77.Sources: EIA, Annual Energy Outlook 2006 DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Tables A9, A

Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.11c. Notes: Includes combined-heat-and-power (CHP) plants whose primary business is to sell electricity and heat to the public. 

plants. Also includes 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 

fuels, blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. Includes na

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 5 Municipal solid waste, landfill gas, sludge waste, tires, agricultural byproducts, and other biomass. Waste included in 6 Includes batteries, chemicals, hydrogen, pitch, sulfur, purchased steam, fuel cells, and miscellaneous technologies. 

NA = not available 
Table 6.4 – Regional Noncoincident 1 Peak Loads and Capacity Margin 

(Megawatts, except as noted) North American Electric Reliability Council Regions 

1990 2000 2001 2002 2003 2004 

Summer Peak 

ECAR 79,258 92,033 100,235 102,996 98,487 102,423 

ERCOT 42,737 57,606 55,201 56,248 59,996 61,432 

FRCC NA 37,194 39,062 40,696 40,475 42,705 

MAAC 42,613 49,477 54,015 55,569 53,566 56,886 

MAIN 40,740 52,552 56,344 56,396 56,988 57,868 MAPP (U.S.) 24,994 28,605 28,321 29,119 28,831 29,244 

NPCC (U.S.) 44,116 50,057 55,949 56,012 55,018 57,535 

SERC 121,943 156,088 149,293 158,767 153,110 157,961 SPP 52,541 40,199 40,273 39,688 40,367 40,089 

WECC2 (U.S.) 97,389 114,602 109,119 119,074 122,537 122,870 

Contiguous U.S. 546,331 678,413 687,812 714,565 709,375 729,013 

ASCC (Alaska) 463 NF NF NF NF NF 

Hawaii NF NF NF NF NF NF 

U.S. Total 546,794 678,413 687,812 714,565 717,652 729,013 

Capacity Margin (%) 3 21.6 15.7 14.5 16.4 18.6 19.2 

1990 2000 2001 

Winter P

67,097 84,546 85,485 

35,815 44,641 44,015 

NA 38,606 40,922 

36,551 43,256 39,458 

32,461 41,943 40,529 

21,113 24,536 21,815 

40,545 43,852 42,670 

117,448 139,146 135,182 

38,949 30,576 29,614 

94,252 97,324 96,622 

484,231 588,426 576,312 6

613 NF NF 

NF NF NF 

484,844 588,426 576,312 6

NA 29.5 28.9 

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 available 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 

interval. 

2 Renamed from WSCC in 20023 The percent by which planned generating capacity resources are expected to be greater (or less) than estimated net inte

demand at the time of expected peak summer (or winter) demand. Net internal demand does not include estimated dema

for direct control load management and customers with interruptible service agreements.
Table 6.5 – Electric-Generator Cumulative Additions and Retirements 

(Gigawatts) 1 

2010 2015 2020 2025 2030 

Cumulative Planned 

Additions 

Coal Steam 8.3 9.3 9.3 9.3 9.3 

Other Fossil Steam 2 0.1 0.1 0.1 0.1 0.1 

Combined Cycle 25.7 25.7 25.7 25.7 25.7 

Combustion Turbine/Diesel 5.3 5.3 5.3 5.3 5.3 

Nuclear 0.0 0.0 0.0 0.0 0.0 

Pumped Storage 0.0 0.0 0.0 0.0 0.0 

Fuel Cells 0.0 0.0 0.0 0.0 0.0 

Renewable Sources 3 10.0 11.0 11.1 11.2 11.4 

Distributed Generation 4 0.0 0.0 0.0 0.0 0.0 

Total Planned Additions 49.4 51.5 51.6 51.7 51.8 

Cumulative Unplanned 

Additions 

Coal Steam 3.4 7.0 32.9 77.7 145.1 

Other Fossil Steam 2 0.0 0.0 0.0 0.0 0.0 

Combined Cycle 0.0 5.5 29.9 41.9 46.8 

Combustion Turbine/Diesel 4.7 11.6 21.5 31.3 46.2 

Nuclear 0.0 2.2 6.0 6.0 6.0 

Pumped Storage 0.0 0.0 0.0 0.0 0.0 

Fuel Cells 0.0 0.0 0.0 0.0 0.0 

Renewable Sources 3 0.4 1.7 4.8 8.3 10.4 

Distributed Generation 4 0.2 0.6 1.4 2.4 5.5 

Total Unplanned Additions 8.8 28.6 96.5 167.7 260.0 

Cumulative Retirements 

Coal Steam 3.0 6.8 6.8 6.8 6.8 

Other Fossil Steam 2 2.0 37.9 44.0 45.1 49.0 

Combined Cycle 0.6 0.6 0.6 0.6 0.6 

Combustion Turbine/Diesel 1.4 8.2 8.2 8.2 8.2 

Nuclear 0.0 0.0 0.0 0.0 0.0 

Pumped Storage 0.0 0.0 0.0 0.0 0.0 

Fuel Cells 0.0 0.0 0.0 0.0 0.0 

Renewable Sources 3 0.1 0.1 0.1 0.1 0.1 

Total Retirements 7.1 53.6 59.8 60.8 64.7 

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C., February 2006), 

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.
Table 6.6 – Transmission and Distribution Circuit Miles 

(Miles) 1 

Voltage 

(kilovolts) 1980 1990 1999 2000 2 2001 2 2002 2 2003 2 2004 2 

230 NA 70,511 76,762 76,437 80,515 81,252 82,238 81,992 

345 NA 47,948 49,250 51,025 53,855 54,827 54,195 55,429 

500 NA 23,958 26,038 25,000 27,343 27,587 27,407 28,011 

765 NA 2,428 2,453 2,426 2,518 2,560 2,560 2,560 

Total NA 144,845 154,503 154,888 164,231 166,226 166,400 167,992 

Sources: EIA, Electricity Transmission Fact Sheets, 

http://www.eia.doe.gov/cneaf/electricity/page/fact_sheets/transmission.html; NERC, Electricity Supply and 

Demand Database, 2005, 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 
Table 7.1 – Electricity Net Generation 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2004 2010 201

Coal 1 1,162 1,594 1,966 1,904 1,933 1,974 1,976 2,218 2,27

Petroleum 2 246 127 111 125 95 119 118 105 10

Natural Gas 3 346 373 601 639 691 650 700 774 1,01

Other Gases 4 NA 10 14 9 11 16 15 12 12 

Total Fossil Energy 1,754 2,104 2,692 2,677 2,730 2,759 2,809 3,108 3,41Nuclear 251 577 754 769 780 764 789 809 82

Hydroelectric Pumped Storage5 NA -4 -6 -9 -9 -9 -8 -9 -

Conventional Hydroelectric 6 279 293 276 217 264 276 270 301 30

Geothermal 5 15 14 14 14 14 14 18 23 

Wood 7 0 33 38 35 39 38 37 76 79 

Waste 8 0 13 23 22 23 24 23 27 28 

Solar Thermal and Photovoltaic NA 0 0 1 1 1 1 2 

Wind NA 3 6 7 10 11 14 51 56 

Total Renewable Energy 285 357 356 295 351 363 359 476 49

Generation for Own Use 9 NA NA NA NA NA NA NA -177 -19

Other 10 NA 4 5 5 6 6 6 12 12 

Total Electricity Generation 2,290 3,038 3,802 3,737 3,858 3,883 3,953 4,388 4,72Sources: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.2a; and EIA, An

DOE/EIA-0383(2006) (Washington, D.C., February 2006), Tables A8 and A16. 

Notes: 

Data include electricity-only and combined-heat-and-power (CHP) plants, whose primary business is to sell electricity – or ele

public. Through 1988, data are for generation at electric utilities only. Beginning in 1989, data also include generation at indepethe 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 ce

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels (including refinery and still 5 Pumped-storage facility production, minus energy used for pumping. Data for 1980 included in conventional hydroelectric pow6 Hydroelectric data through 1988 are for generation at electric utilities and industrial plants only; beginning in 1989, data also in

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. 

NA = not available 
Table 7.2 – Net Generation at Electricity-Only Plants 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 

Coal 1 1,162 1,560 1,911 1,852 1,881 1,916 1,916 2,164 2,209 

Petroleum 2 246 118 98 113 83 109 108 90 89 

Natural Gas 3 346 265 399 427 457 421 486 533 743 Other Gases 4 NA 0 0 0 0 0 0 NA NA 

Total Fossil Energy 1,754 1,942 2,408 2,392 2,422 2,446 2,510 2,787 3,041 Nuclear 251 577 754 769 780 764 789 809 829 

Hydroelectric Pumped Storage5 NA -4 -6 -9 -9 -9 -8 -9 -9 

Conventional Hydroelectric 6 276 290 271 214 260 272 264 297 297 

Geothermal 5 15 14 14 14 14 14 18 23 

Wood 7 0.3 6 7 7 7 7 7 45 45 

Waste 8 0.2 10 18 17 17 18 18 25 26 Solar Thermal and Photovoltaic NA 0.4 0.5 0.5 0.6 0.5 0.6 1 1 Wind NA 3 6 7 10 11 14 51 56 

Total Renewable Energy 282 324 316 259 311 323 319 436 448 Other 10 0 0 0 0 1 1 3 NA NA 

Total Electricity Generation 2,286 2,840 3,473 3,411 3,505 3,525 3,611 4,020 4,306 

Sources: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005),Table 8.2c; and EIA, A

2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), 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. Thro

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 fue

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels (including refinery and 5 Pumped-storage facility production, minus energy used for pumping. Data for 1980 included in conventional hydroelectric p6 Hydroelectric data through 1988 are for generation at electric utilities and industrial plants only; beginning in 1989, data als

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. 

NA = not available 
Table 7.3 – Electricity Generation at Combined-Heat-and-Power Plants 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 2

Coal 1 NA 34 56 52 52 58 61 53 68 

Petroleum 2 NA 9 13 12 11 11 10 15 15 

Natural Gas 3 NA 108 202 212 234 229 213 241 275 

Other Gases 4 NA 10 14 9 11 15 15 4 4 

Total Fossil Energy NA 161 284 285 309 313 299 313 363 4

Nucl ear NA 0 0 0 0 0 0 0 0 

Hydroelectric Pumped Storage5 NA 0 0 0 0 0 0 0 0 

Conventional Hydroelectric 6 NA 3 4 3 4 4 5 4 4 

Geothermal NA 0 0 0 0 0 0 0 0 

Wood 7 NA 27 30 29 31 30 30 32 35 

Waste 8 NA 3 6 5 5 6 5 2 2 

Solar Thermal and Photovolt aic NA 0 0 0 0 0 0 1 1 

Wind NA 0 0 0 0 0 0 0 0 Total Renewable Energy NA 33 40 36 41 40 40 40 43 

Other 9 NA 4 5 5 4 5 3 12 12 

Total Electricity Generation NA 198 329 326 354 358 342 364 417 4

Sources: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005),Table 8.2c and 8

Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Tables A8 and A16. Notes: Includes combined-heat-and-power (CHP) plants, whose primary business is to sell electricity and heat to the public. utility CHP plants. Also includes commercial and industrial CHP and a small number of commercial and industrial (endelectricity-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, plus a small amount of supplemental gaseous fuels that cannot be identified separately. Forecast data 

generation from fuel cells. 4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels (including refiner

5 Pumped-storage facility production, minus energy used for pumping. 6 Includes CHP plants that use multiple sources of energy, including hydropower. 7Wood, 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. 

NA = not available 
Table 7.4 – Generation and Transmission/Distribution Losses

(Billion kWh) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 2

Net Generation Delivered 2,290 3,038 3,802 3,737 3,858 3,883 3,953 4,211 4,536 4

Generation Losses 1 4,859 6,316 7,809 7,617 7,798 7,756 8,006 8,339 8,764 9

Transmission and Distribution Losses 2 NA 219 258 243 266 257 271 251 254 

Sources: Calculated from EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), T8.2a, and 8.4a; and EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Table

A8. 

Notes: 

1 Generation Losses for all years are calculated by calculating a Gross Generation value in billion kWh by multiplying th

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 Need

= Total Generation from Electric Generators + Cogenerators + Net Imports - Generation for Own Use. Represents enerbetween the point of generation and delivery to the customer, and data collection frame differences and nonsampling eNA = not available 
Table 7.5 – Electricity Trade 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 2

Interregional Electricity Trade Gross Domestic Firm Power Trade NA NA NA 143 139 137 142 105 82 Gross Domestic Economy Trade NA NA NA 182 174 215 233 231 200 Gross Domestic Trade NA NA NA 325 313 352 376 337 283 International Electricity Trade Firm Power Imports from Mexico and Canada NA NA NA 12 10 11 12 3 2 Economy Imports from Mexico and Canada NA NA NA 26 27 19 22 40 39 Gross Imports from Mexico and Canada 25 18 49 39 36 30 34 42 41 Firm Power Exports to Mexico and Canada NA NA NA 7 6 5 7 1 1 Economy Exports to Mexico and Canada NA NA NA 10 9 19 16 20 17 Gross Exports to Canada and Mexico 4 16 15 16 14 24 23 21 18 Sources: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.1; and Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Table A10. Notes: All data are from EIA AEO except Gross Imports and Exports for 1980-2004. NA = not available 
Table 8.1 – Electricity Sales 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 2

Electricity Sales by Sector1 Residential 717 924 1,192 1,203 1,267 1,273 1,293 1,461 1,576 1

 Commercial 559 838 1,159 1,197 1,218 1,200 1,229 1,430 1,592 1

 Industrial 815 946 1,064 964 972 1,008 1,021 1,060 1,103 1

 Transportation/Other 2 3 5 5 5 6 7 8 26 28 

Total Sales 2,094 2,713 3,421 3,370 3,463 3,488 3,551 3,978 4,300 4

Direct Use 3 NA 125 171 163 166 168 166 177 192 

Total 2,094 2,837 3,592 3,532 3,629 3,656 3,717 4,155 4,491 4

Sources: 2010-2030 - EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Table A8; 

Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), 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 interde

through 2002. Transportation-sector sales reported starting in 2010. 

3 Commercial and industrial facility use of on-site net electricity generation; and electricity sales among adjacent or colocated fa

information is not available. 
Table 8.2 – Demand-Side Management 

1980 1990 2000 2001 2002 

Load Management Peak Load Reductions (MW)1 NA NA 10,027 11,928 9,516 

Energy Efficiency Peak Load Reductions (MW)2 NA NA 12,873 13,027 13,420 

Total Peak Load Reductions (MW) NA 13,704 22,901 24,955 22,936 

Energy Savings (Million kWh) Costs (Million 2004$)3 

NA 

NA 

20,458 

1,562 

53,701 

1,694 

54,762 

1,723 

54,075 

1,690 

Sources: 1980-2003 - EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.13; 2Annual 2004 Tables, (Washington, D.C., December 2005), Table 9.1, 9.2, 9.4, 9.6, and 9.7 http://www.eia.doe.gov/cneaf/electriNotes: The actual reduction in peak load reflects the change in demand for electricity that results from a utility demand-side managemeat the time that the utility experiences its actual peak load, as opposed to the potential installed peak load reduction capability. Dand 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 

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. Beginnprograms are included under load management. 

3 Historical data converted to 2004 dollars using EIA Annual Energy Review 2004, Appendix D. 
Table 8.3 – Electricity Sales, Revenue, and Consumption by Census Division and Sta

Average Electricity 

Census Division Revenue Revenue Consumption Census Division Revenue 

and State Sales (MWh) (million $) (¢/kWh) (kWh/person) and State Sales (MWh) (million $

New England 125,249 13,284 10.6 8,796 East South Central 319,085 18,6

Connecticut 32,215 3,305 10.3 9,177 Alabama 86,871 5,2

Maine 12,368 1,198 9.7 9,359 Kentucky 86,521 4,0

Massachusetts 56,142 6,045 10.8 8,774 Mississippi 46,033 3,2New Hampshire 10,973 1,248 11.4 8,377 Tennessee 99,661 6,1

Rhode Island 7,888 865 11.0 7,329 West South Central 494,966 36,9

Vermont 5,664 624 11.0 9,090 Arkansas 43,672 2,4

Middle Atlantic 366,176 37,679 10.3 9,063 Louisiana 79,737 5,6New Jersey 77,593 7,984 10.3 8,900 Oklahoma 50,942 3,3New York 145,082 18,209 12.6 7,535 Texas 320,615 25,4

Pennsylvania 143,501 11,486 8.0 11,545 Mountain 237,632 16,3

East North Central 571,151 37,920 6.6 12,374 Arizona 66,933 4,9

Illinois 139,254 9,465 6.8 10,910 Colorado 46,724 3,2Indiana 103,094 5,749 5.6 16,437 Idaho 21,809 1,0

Michigan 106,606 7,401 6.9 10,533 Montana 12,957 8

Ohio 154,221 10,629 6.9 13,453 Nevada 31,312 2,6

Wisconsin 67,976 4,677 6.9 12,278 New Mexico 19,846 1,4

West North Central 261,030 16,095 6.2 13,173 Utah 24,512 1,3

Iowa 40,903 2,619 6.4 13,789 Wyoming 13,540 6

Kansas 37,127 2,364 6.4 13,527 Pacific Contiguous 378,382 36,4

Minnesota 63,340 3,950 6.2 12,340 California 252,764 28,9

Missouri 74,054 4,494 6.1 12,767 Oregon 45,636 2,8

Nebraska 25,876 1,475 5.7 14,712 Washington 79,982 4,6

Pacific 

North Dakota 10,516 599 5.7 16,518 Noncontiguous 16,520 2,3

South Dakota 9,214 594 6.4 11,875 Alaska 5,788 6
South Atlantic 778,026 54,874 7.1 13,973 Hawaii 10,732 1,6

Delaware 11,761 885 7.5 13,943 U.S. Total 3,548,218 270,4

District of Columbia 11,415 852 7.5 225,943 Florida 218,584 17,835 8.2 12,287 Georgia 129,466 8,525 6.6 14,270 Maryland 66,892 4,785 7.2 11,944 

North Carolina 125,657 8,756 7.0 14,471 South Carolina 79,908 4,972 6.2 18,780 Virginia 105,424 6,780 6.4 13,931 West Virginia 28,919 1,483 5.1 15,917 

Sources: EIA, Electric Sales and Revenue 2004 Spreadsheets, Data Tables, http://www.eia.doe.gov/cneaf/electricity/esr/esr_s

and U.S. Census Bureau, Annual Estimates of the Population for the United States and States, and for Puerto Rico: April 1, 200

EST2004-01) - State Population Estimates 2005, http://www.census.gov/popest/states/tables/NST-EST2005-01.xls 

Notes: Revenue in 2004 dollars. 

Includes bundled and unbundled consumers
Table 9.1 – Price of Fuels Delivered to Electric Generators

(2004 Dollars per Million Btu) 1 

1980 1993 2000 2001 2002 2003 2004 2010 2015 

Distillate Fuel NA NA NA NA 

NA 6.65 9.23 9.04 9.02 

Residual Fuel 2 NA 2.88 4.48 3.87 3.44 4.40 4.29 5.70 5.72 

Natural Gas 3 NA 3.11 4.61 4.70 3.67 5.46 5.96 5.46 5.08 Steam Coal 4 NA 1.69 1.29 1.29 1.29 1.29 1.36 1.48 1.40 Fossil Fuel Average 5 NA 1.93 1.86 1.81 1.56 2.31 2.57 2.41 2.41 Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Table A3; and EIA, Elec

DOE/EIA-0348(2004) (Washington, D.C., November 2005), Table 4.5. 

Notes: Includes electricity-only and combined-heat-and-power plants whose primary business is to sell electricity - or electricity and hea

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 p

combined-heat-and-power producers are included in this data dissemination. Prior to 2002, these data were not collected; the d

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 o

jet 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.

NA = not available 
Table 9.2 – Electricity Retail Sales 

(Billion Kilowatthours) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 

Retail Sales 1 

Residential 717 924 1,192 1,203 1,267 1,273 1,293 1,461 1,576 1

Commercial 2 559 838 1,159 1,197 1,218 1,200 1,229 1,430 1,592 1

Industrial 3 815 946 1,064 964 972 1,008 1,021 1,060 1,103 1Transportation 4 3 5 5 5 6 7 8 26 28 

Total 5 2,094 2,713 3,421 3,370 3,463 3,488 3,551 4,155 4,491 4

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006), (Washington, D.C., February 2006), Table A8; and EIA, A

2004, DOE/EIA-0384(2004) (Washington, D.C., September 2005), Table 8.9. 

Notes: 

1 Electricity retail sales to ultimate customers reported by electric utilities and, beginning in 1996, other energy-service provider2 Commercial sector, including public street and highway lighting, interdepartmental sales, and other sales to public authorities3Industrial sector. Through 2002, excludes agriculture and irrigation; beginning in 2003, includes agriculture and irrigation.4Transportation sector, including sales to railroads and railways. 5The sum of "Residential," "Commercial," "Industrial," and "Transportation."
Table 9.3 – Prices of Electricity Sold 

(2003 cents per Kilowatthour) 1 

1980 1990 2000 2001 2002 2003 2004 2010 2015 2020 20

Price by End-Use Sector2 

Residential 10.8 10.4 8.9 9.1 8.8 8.9 8.9 8.5 8.3 8.3 8Commercial 11.0 9.7 8.0 8.4 8.2 8.1 8.2 7.6 7.4 7.5 7Industrial 7.4 6.3 5.0 5.3 5.1 5.2 5.1 5.3 5.1 5.2 5Transportation / Other3 9.6 8.5 7.1 7.4 7.0 7.7 6.5 7.1 6.9 7.0 7

End-Use Sector Average 9.4 8.7 7.4 7.7 7.5 7.6 7.6 7.3 7.1 7.2 7Price by Service Category2 

Generation NA NA NA NA NA 5.0 5.8 4.7 4.6 4.8 5Transmission NA NA NA NA NA 0.5 0.5 0.6 0.6 0.7 0Distribution NA NA NA NA NA 2.1 2.0 2.0 1.9 1.9 1Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006), (Washington, D.C., February 2006), Table A8; and EIA, A

Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 8.10. Notes: For 1980, data are for selected Class A utilities whose electric operating revenues were $100 million or more during the previo

For 1990, data are for a census of electric utilities. For 2000 onward, data also include energy-service providers selling to retai

1 Historical data real prices expressed in chained (2004) dollars, calculated by using gross domestic product implicit price defla

EIA Annual Energy Review 2004 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 sale

NA = not available 
Table 9.4 – Revenue from Electric-Utility Retail Sales by Sector 

(Millions of 2004 Dollars) 

1980 1990 2000 2001 2002 2003 2004 2010 2015 2020 2025 

Residential 77,598 95,980 106,351 109,579 111,453 113,090 115,594 124,185 130,808 140,353 150,108 

Commercial 61,537 81,624 93,235 100,369 99,536 97,760 100,369 108,680 117,808 132,150 149,688 

Industrial 60,399 59,455 53,448 51,368 49,331 52,803 52,173 56,180 56,259 59,658 64,533 

Transportation/Other 1 289 424 355 372 420 542 519 1,846 1,932 2,030 

All Sectors 2 197,153 236,419 252,190 260,731 259,589 264,291 268,811 303,315 318,865 348,741 385,392 

Sources: Calculated from EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006), (Washington, D.C., February 2006), Table 

Annual Energy Review 2004, DOE/EIA-0384 (2004) (Washington, D.C., August 2005), 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 previo

For 1990, data are for a census of electric utilities. For 2000 onward, data also include energy-service providers selling to retail customers 
Table 9.5 – Revenue from Sales to Ultimate Consumers by Sector, Census Division, a

(Millions of 2004 Dollars) Census Division/ Residen- Commer- Census Division/ Residen- CommerState tial cial Industrial Other1 All Sectors 2 State tial cial IndNew England 5,560 5,696 1,995 33 13,284 East South Central 7,934 5,551 

Connecticut 1,537 1,332 423 14 3,305 Alabama 2,295 1,506 

Maine 527 428 244 - 1,198 Kentucky 1,538 1,034 Massachusetts 2,323 2,858 844 19 6,045 Mississippi 1,444 1,019 

New Hampshire 535 480 233 - 1,248 Tennessee 2,657 1,992 Rhode Island 366 373 126 - 865 West South Central 16,701 11,299 

Vermont 273 226 126 - 624 Arkansas 1,150 605 Middle Atlantic 14,890 17,221 5,266 302 37,679 Louisiana 2,324 1,710 

New Jersey 3,148 3,793 1,012 32 7,984 Oklahoma 1,520 1,116 

New York 6,890 9,654 1,455 210 18,209 Texas 11,707 7,867 Pennsylvania 4,853 3,774 2,799 60 11,486 Mountain 6,732 5,975 

East North Central 14,847 12,855 10,187 32 37,920 Arizona 2,447 1,901 

Illinois 3,638 3,570 2,232 25 9,465 Colorado 1,307 1,343 Indiana 2,277 1,448 2,022 1 5,749 Idaho 446 294 

Michigan 2,759 2,925 1,717 0 7,401 Montana 319 321 

Ohio 4,251 3,510 2,864 5 10,629 Nevada 1,034 752 Wisconsin 1,922 1,401 1,353 - 4,677 New Mexico 488 609 West North Central 7,044 5,505 3,544 1 16,095 Utah 528 551 

Iowa 1,132 731 756 - 2,619 Wyoming 163 203 

Kansas 962 893 510 - 2,364 Pacific Contiguous 13,990 16,307 

Minnesota 1,624 1,287 1,038 1 3,950 California 10,628 13,554 

Missouri 2,185 1,648 661 0 4,494 Oregon 1,293 1,010 

Nebraska 610 497 369 - 1,475 Washington 2,069 1,742 
Pacific 

North Dakota 249 225 124 - 599 Noncontiguous 828 874 

South Dakota 283 224 87 - 594 Alaska 256 286 

South Atlantic 27,510 18,973 8,310 80 54,874 Hawaii 571 588 

Delaware 378 300 207 - 885 U.S. Total 116,037 100,255 District of Columbia 147 670 13 22 852 Florida 10,086 6,601 1,140 7 17,835 Georgia 4,016 2,912 1,587 9 8,525 Maryland 2,181 1,304 1,269 31 4,785 North Carolina 4,369 2,871 1,516 - 8,756 South Carolina 2,267 1,390 1,315 - 4,972 Virginia 3,397 2,530 843 10 6,780 West Virginia 670 394 419 0 1,483 Source: EIA, Electric Sales and Revenue 2004 Spreadsheets, Data Tables, http://www.eia.doe.gov/cneaf/electricity/esr/esr_tabs.html, Table 1c. Notes: 

1 Includes sales for public street and highway lighting, to public authorities, railroads and railways, and interdepartmental sales. 2 Includes bundled and unbundled consumers. 
Table 9.6 – Production, Operation, and Maintenance Expenses for Major U.S. 

Investor-Owned and Publicly Owned Utilities (Million of Nominal Dollars) Production Expenses Cost of Fuel  Purchased Power  Other Production Expenses Total Production Expenses2 Operation and Maintenance Expenses Transmission Expenses  Distribution Expenses  Customer Accounts Expenses  Customer Service and Information Expenses  Sales Expenses  Administrative and General Expenses Total Electric Operation and Maintenance Expenses 

Investor-Owned Utilities Publicl

1990 1995 2000 2002 2003 2004 1990 199

32,635 29,122 32,555 24,132 26,476 28,678 5,276 5,66

20,341 29,981 61,969 58,828 62,173 67,354 10,542 11,98

9,526 9,880 12,828 7,688 7,532 8,256 155 21

62,502 68,983 107,352 90,649 96,181 104,288 15,973 17,86

1,130 1,425 2,699 3,494 3,585 4,519 604 66

2,444 2,561 3,115 3,113 3,185 3,301 950 63

3,247 3,613 4,246 4,165 4,180 4,087 375 44

1,181 1,922 1,839 1,821 1,893 2,012 75 12

212 348 403 261 234 238 29 3

10,371 13,028 13,009 12,872 13,466 13,519 1,619 2,12

18,585 22,897 25,311 25,726 26,543 27,676 3,653 4,01

Source: EIA, Electric Power Annual 2004, DOE/EIA-0348(2004) (Washington, D.C., November 2005), Tables 8.1, 8.3, and 8.4; Annual 2001, DOE/EIA-0348(2001) (Washington, D.C., December 2002), Table 8.1; EIA, Financial Statistics of Major US Public1994, DOE/EIA-0437(94)/2 (Washington, D.C., December 1995), Table 8 and Table 17; EIA, Financial Statistics of Major US Pu1999, DOE/EIA-0437(99)/2 (Washington, D.C., November 2000), Table 10 and Table 21; EIA, Financial Statistics of Major US P2000, DOE/EIA-0437(00)/2 (Washington, D.C., November 2001), Table 10 and Table 21.; EIA, Public Electric Utility Database (

Notes: 

1 Publicly Owned Utilities include generator and nongenerator electric utilities. 2 Totals may not equal sum of components, because of independent rounding. 3 Collection of Form EIA-412 has been suspended, data for 2004 not available. 

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 2004 

Utility Operating Expenses 142,471 165,321 210,324 188,745 197,459 207,161 

Electric Utility 127,901 150,599 191,329 171,291 175,473 182,337 

Operation 81,086 91,881 132,662 116,374 122,723 131,962 

Production 62,501 68,983 107,352 90,649 96,181 104,287 

Cost of Fuel 32,635 29,122 32,555 24,132 26,476 28,678 

Purchased Power 20,341 29,981 61,969 58,828 62,173 67,354 

Other 9,526 9,880 12,828 7,688 7,532 8,256 

Transmission 1,130 1,425 2,699 3,494 3,585 4,519 

Distribution 2,444 2,561 3,115 3,113 3,185 3,301 

Customer Accounts 3,247 3,613 4,246 4,165 4,180 4,087 

Customer Service 1,181 1,922 1,839 1,821 1,893 2,012 

Sales 212 348 403 261 234 238 

Administrative and General 10,371 13,028 13,009 12,872 13,466 13,519 

Maintenance 11,779 11,767 12,185 10,843 11,141 11,774 

Depreciation 14,889 19,885 22,761 17,319 16,962 16,373 

Taxes and Other 20,146 27,065 23,721 26,755 24,648 22,228 

Other Utility 14,571 14,722 18,995 17,454 21,986 24,823 

Operation (Mills per 

Kilowatthour) 1 

Nuclear 10.04 9.43 8.41 8.54 8.86 8.3 

Fossil Steam 2.21 2.38 2.31 2.54 2.50 2.68 

Hydroelectric and Pumped 

Storage 3.35 3.69 4.74 5.07 4.50 5.05 

Gas Turbine and Small Scale 2 8.76 3.57 4.57 2.72 2.76 2.73 

Maintenance (Mills per 

Kilowatthour) 1 

Nuclear 5.68 5.21 4.93 5.04 5.23 5.38 

Fossil Steam 2.97 2.65 2.45 2.68 2.73 2.96 

Hydroelectric and Pumped 

Storage 2.58 2.19 2.99 3.58 3.01 3.64 

Gas Turbine and Small Scale 2 12.23 4.28 3.50 2.38 2.26 2.16 

Source: EIA, Electric Power Annual 2004, DOE/EIA-0348(2004) (Washington, D.C., November 2005), 

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. 
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/EIA-0437(99)/2 (Washington, D.C., November 2000), Table 10 and Table 21; EIA,

Financial Statistics of Major U.S. Publicly Owned Electric Utilities 2000, DOE/EIA-0437(00)/2 (Washington, D.C., 

November 2001), Table 10 and 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: EIA suspended collection of this dataset in 2004. 1

 Totals may not equal sum of components, because of independent rounding.

2

 Number of employees was 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. 

NA = not available 
Table 9.7 – Environmental Compliance Equipment Costs

(Nominal Dollars) 

1990 1995 2000 2001 2002 2003 2004 

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 1.38 

Average Installed Costs ($/kW) 118 126 124 131 124 124 145 

Source: Electric Power Annual 2004, Table 5.3., DOE/EIA-0348(04) (November 2005). EIA, Electric Power Annual 

2001, DOE/EIA-0348(01) (March 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. 
Table 10.1 – Consumer Price Estimates for Energy Purchases 

(2004 Dollars, per Million Btu)1 

1970 1980 1990 2000 2005 2010 2015 20

Coal 1.49 2.92 1.98 1.34 1.52 1.51 1.43 1Natural Gas 2.32 5.73 5.07 6.08 9.60 7.19 6.60 6

 Distillate Fuel 4.56 13.42 10.19 10.67 15.28 13.30 13.72 14

 Jet Fuel 2.87 12.74 7.54 7.14 12.64 9.67 9.87 10 Liquified Petroleum Gases 5.74 11.30 8.97 11.03 18.04 13.39 13.19 14

Motor Gasoline 11.20 19.71 12.10 13.00 18.60 16.52 16.34 17

Residual Fuel 1.65 7.77 4.21 4.68 6.79 6.07 6.03 6

 Other 2 5.42 14.10 7.72 7.54 NA NA NA 

Petroleum Total 6.76 14.82 9.91 10.73 15.28 13.30 13.72 14

Nuclear Fuel 0.71 0.86 0.89 0.50 N/A N/A N/A N

Wood and Waste 5.07 4.53 1.72 1.73 N/A N/A N/A N

Primary Energy Total 3 4.25 9.15 5.90 6.18 13.61 11.52 11.40 11

Electric Utility Fuel 1.26 3.52 1.95 1.78 NA NA NA 

Electricity Purchased by End Users 19.58 27.94 25.64 21.69 24.44 21.43 20.87 21Total Energy 3 6.49 13.80 10.94 11.18 15.57 13.32 13.16 13

1.49 2.92 1.98 1.34 1.52 1.51 1.43 1

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006), (Washington, D.C., February 2006), Table A3; and EIA, 

2004, DOE/EIA-0384 (2004) (Washington, D.C., August 2005), Table 3.3. 

Notes: 

1 Historical data converted to 2004$/MMBtu using GDP deflators from EIA, Annual Energy Review 2004, DOE/EIA-0384(2004

September 2005), Table D.1. 2 Consumption-weighted average price for asphalt and road oil, aviation gasoline, kerosene, lubricants, petrochemical feedsto

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.

NA = not available 
Table 10.2 – Economy-Wide Indicators 

(Billions of 2000 Chain Weighted Dollars, unless otherwise noted) 

1980 1990 2000 2004 2010 2015 2020 

GDP Chain Type Price Index (2000 = 1.000) 0.541 0.816 1.000 1.091 1.235 1.398 1.597 Real Gross Domestic Product 5,162 7,113 9,817 10,756 13,043 15,082 17,541  Real Consumption 3,374 4,770 6,739 7,589 9,128 10,373 11,916  Real Investment 645 895 1,736 1,810 2,259 2,713 3,293  Real Government Spending 1,115 1,530 1,722 1,952 2,150 2,296 2,464  Real Exports 324 553 1,096 1,118 1,831 2,671 3,776  Real Imports 311 607 1,476 1,719 2,295 2,857 3,659 Real Disposable Personal Income 3,858 5,324 7,194 8,004 9,622 11,058 13,057 Consumer Price Index (2002 = 1.000) 0.824 1.307 1.722 1.889 2.153 2.464 2.862 Unemployment Rate (percent) 7.1 5.6 4.0 5.5 4.7 4.6 4.4 Housing Starts (millions) 1.3 1.2 1.6 2.1 2.0 2.0 1.9 Gross Output Total Industrial 5,643 6,355 7,036 7,778 Non-Manufacturing 1,439 1,572 1,689 1,808 Manufacturing 4,204 4,783 5,347 5,969 Energy-Intensive Manufacturing 1,161 1,265 1,350 1,441 Non-Energy-Intensive Manufacturing 3,044 3,518 3,997 4,528 Population (all ages, millions) 226.5 248.8 281.4 294.1 310.1 323.5 337.0 Employment Non-Agriculture (millions) 95.9 115.6 134.4 131.4 142.1 147.6 156.2 Employment Manufacturing (millions) 20.4 19.2 17.5 14.3 14.0 13.5 13.3 Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383(2006) (Washington, D.C., February 2006), Table A19; EIA, Annua

2003, DOE/EIA-0384(2003) (Washington, D.C., October 2004), Table D1, Bureau Of Economic Analysis, National Income and Tables (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, Departmenof Labor Statistics, Current Population Survey, Current Population Survey, Household Data Annual Averages, http://www.bls.gov/cps/cpsa2003.pdf, National Association of Home Builders, http://www.nahb.org/generic.aspx?sectionID=130&genericContentID=554. 
Table 10.3 – Composite Statements of Income for Major U.S. Publicly Owned Gene

and Investor-Owned Electric Utilities, 2004 (Million 2004 Dollars) 

Investor-Owned Publicly Owned Generator Cooperative Borrowe

Electric Utilities Electric Utilities 1, 2 Owned Electric Utilitie

Operating Revenue - Electric 213,539 46,360 30,

Operating Expenses - Electric 182,337 41,118 27,

Operation Including Fuel 131,962 32,737 25,

 Production 104,287 26,813 20,

 Transmission 4,519 977  Distribution 3,301 1,044 1,

 Customer Accounts 4,180 754 

 Customer Service 2,012 311  Sales 238 95 

 Administrative and General 13,519 2,742 1,Maintenance 11,774 2,504 Depreciation and Amortization 16,373 4,555 2,Taxes and Tax Equivalents 22,228 1,323 

Net Electric Operating Income 33,158 5,242 2,Source: EIA, Electric Power Annual 2004, DOE/EIA-0348(2003), (Washington, D.C., November 2005), Tables 8.1, 8.3, 8.4Note: 

1 The data represent those utilities meeting a threshold of 150 million kilowatthours of customer sales or resale for the two p2 Values for 2003. In 2004, Form EIA-412 has been suspended until further notice. Includes utilities with and without gener

NA= not available 
Table 11.1 – Emissions from Electricity Generators 

 (Thousand short tons of gas) 

1990 2000 2001 2002 2003 2004 2010 2015 

Coal Fired  Carbon Dioxide 1,674,521 2,090,644 2,034,867 2,043,795 2,086,014 2,087,667 2,367,580 2,412,270 2,58

Sulfur Dioxide 15,220 10,623 10,004 9,732 NA NA NA NA 

 Nitrogen Oxide 5,642 4,563 4,208 4,094 NA NA NA NA 

Methane 11 13 13 13 13 13 NA NA 

 Nitrous Oxide 25 31 31 31 31 32 NA NA 

Petroleum Fired  Carbon Dioxide 111,223 100,200 111,885 85,870 107,034 107,365 82,091 81,142 8

Sulfur Dioxide 639 482 529 343 NA NA NA NA 

 Nitrogen Oxide 221 166 170 130 NA NA NA NA 

Methane 1 1 1 1 1 1 NA NA 

 Nitrous Oxide 1 1 1 1 1 1 NA NA 

Gas Fired  Carbon Dioxide 194,999 310,190 319,119 336,866 306,002 326,174 327,857 425,185 44

Sulfur Dioxide 1 232 262 8 NA NA NA NA 

 Nitrogen Oxide 565 422 359 270 NA NA NA NA 

Methane 0 1 1 1 1 1 NA NA 

 Nitrous Oxide 0 1 1 1 1 1 NA NA 

Other 1

 Carbon Dioxide NA NA NA 

NA NA 14,290 15,024 1

Sulfur Dioxide 2 49 59 55 210 NA NA NA NA 

 Nitrogen Oxide 2 235 180 180 206 NA NA NA NA 

Methane NA NA NA 

NA NA NA NA NA 

 Nitrous Oxide 3 1 1 0 1 1 1 NA NA 

Total Carbon Dioxide 1,987,578 2,512,498 2,478,216 2,480,862 2,511,947 2,533,773 2,791,819 2,933,621 3,12

Sulfur Dioxide 15,909 11,396 10,850 10,293 10,596 10,888 6,515 5,101 
 Nitrogen Oxide 6,663 5,330 4,917 4,699 4,119 3,742 2,585 2,312 

Mercury NA NA NA 50,081 50,695 53,306 41,595 26,503 2

Methane 12 14 14 14 14 14 NA NA 

 Nitrous Oxide 26 33 33 33 33 33 NA NA 

Sulfur Hexafluoride 4 2 1 1 1 1 1 NA NA 

Sources: EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2005) (Washington, D.C., February 2006), Tables A8 and A18; EI

Gases in the United States 2004, DOE/EIA-0573(2003) (Washington, D.C., November 2005) Tables 10, 17, 25, 29; and EPA, N

Air Pollutant Emission Trends, “Average Annual Emissions, All Criteria Pollutants,” August 2004, http://www.epa.gov/ttn/chief/tre

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

global warming potential that is 22,200 times that of carbon dioxide and has an atmospheric lifetime of 3,200 years.

NA = not available 
Table 11.2 – Installed Nameplate Capacity of Utility Steam-Electric Generators With 

Environmental Equipment (Megawatts) 

1990 2000 2001 2002 2003 2004 

Coal Fired 

Particulate Collectors 315,681 321,636 329,187 329,459 328,587 NA

 Cooling Towers 134,199 146,093 154,747 154,750 155,158 NA 

Scrubbers 69,057 89,675 97,804 98,363 99,257 NA

 Total1 317,522 328,741 329,187 329,459 328,587 NA 

Petroleum and Gas Fired 

Particulate Collectors 33,639 31,090 31,575 29,879 29,422 NA

 Cooling Towers 28,359 29,427 34,649 45,747 55,770 NA 

Scrubbers 65 0 184 310 310 NA

 Total1 59,372 57,697 61,634 71,709 81,493 NA 

Total 

Particulate Collectors 349,319 352,727 360,762 359,338 358,009 355,782

 Cooling Towers 162,557 175,520 189,396 200,497 210,928 214,989 

Scrubbers 69,122 89,675 97,988 98,673 99,567 101,492

 Total1 376,894 386,438 390,821 401,168 409,954 409,769 

Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., September 2005), Table 12.8. 2004 Total EIA Electric Power Annual. DOE/EIA-0348(2004), http://www.eia.doe.gov/cneaf/electricity/epa/epat5p2.html, Table 5.2. 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 

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. 

NA = not available 
Table 11.3 – EPA-Forecasted Nitrogen Oxide, Sulfur Dioxide, and Mercury Emissions 

Generators 

2007 

EPA Base Case 2004 

2010 2015 2020 

SO2 (Thousand Tons) 

NOx (Thousand Tons) CO2 (Thousand Tons) 

10,374 

3,665 

2,391 

9,908 

3,679 

2,470 

9,084 

3,721 

2,599 

8,876 

3,758 

2,796 

EPA CAIR Case 20

2007 2010 

7,733 6,351 

3,600 2,453 

2,365 2,452 

Source: Environmental Protection Agency (EPA), Runs Table for EPA Modeling Applications 2004, using IPM http://www.epa.gipm/iaqr.html, EPA Base Case for 2004 Analyses http://www.epa.gov/airmarkets/epa-ipm/iaqr/basecase2004.zip, and 2004 CAIhttp://www.epa.gov/airmarkets/epa-ipm/iaqr/cair2004_final.zip 

Notes: 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 upublic and private-sector clients, IPM is a multiregional, dynamic, deterministic linear programming model of the U.S. electric-po• The model provides forecasts of least-cost capacity expansion, electricity dispatch, and emission-control strategies for meeting and environmental, transmission, dispatch, and reliability constraints. IPM can be used to evaluate the cost and emissions impapolicies to limit emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), and mercury (Hg) from the electr
Table 11.4 – Origin of 2004 Allowable SO2 Emissions Levels 

Number of SO2 

Allowances 

Type of Allowance Allocation Explanation of Allowance Allocation TypInitial Allocation 9,191,897 Initial allocation is the number of allowances granted to units, based 

historic utilization and emissions rates specified in the Clean Air Act

Allowance Auctions 250,000 The allowance auction provides allowances to the market that were 

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 2004. 

TOTAL 2004 ALLOCATION 9,541,085 Banked Allowances 8,646,818 Banked Allowances are those allowances accrued in a unit's accoun

which can be used for compliance in 2004 or any future year. 

TOTAL 2004 ALLOWABLE 18,187,903 Source: EPA, Acid Rain Program 2004 Progress Report, Document EPA-430-R-05-011, November 2005, 

Figure 4. http://www.epa.gov/airmarkets/cmprpt/arp04/2004report.pdf 
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) 11,558,205 2,232,495 6,594,096 78,312,583 

(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) 36,449,954,187 17,600,991,128 46,211,427,727 303,176,455,525 552

(E) Competing Heat Rate (Btu/kWh) 10,107 10,107 10,107 10,107 

(F) Annual Output (Trillion Btu) 368 178 467 3,064

(G) Carbon Coefficient (MMTCB/Trillion Btu) 0.01783 0.01783 0.01783 0.01783 

(H) Annual Carbon Displaced (MMTC) 6.569 3.172 8.328 54.635 Sources:Capacity: Projected values for the year 2006 from EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C

A16, 2005.

Capacity factors: Hydropower calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., Fe

All others based on DOE, Renewable Energy Technology Characterizations, EPRI TR-109496, 1997, and program data.

Heat Rate: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table A6.Carbon Coefficient: DOE, GPRA2003 Data Call, Appendix B, page B-16, 2003. Notes: For illustrative purposes only, displacement of fossil generation depends on power system generation portfolio and dispatch or

Capacity values exclude combined-heat-and-power (CHP) data, but include end-use sector (industrial and commercial) non-CCompeting heat rate from Fossil-Fueled Steam-Electric Plants heat rate. 

 201
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) 11,558,205 2,232,495 6,594,096 78,312,583 28

(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) 36,449,954,187 17,600,991,128 46,211,427,727 303,176,455,525 552,57

(E) Average Annual Household Electricity Consumption (kWh) 11,586 11,586 11,586 11,586 1

(F) Number of Households 3,148,804 1,520,497 3,992,068 26,190,515 4

Sources: Capacity: Projected values for the year 2006 from EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washin

2006), Table A16, 2006. 

Capacity factors: Hydropower calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., Fe

A16. All others based on DOE, Renewable Energy Technology Characterizations, EPRI TR-109496, 1997, and program data. Household electricity consumption: Calculated from EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.A4 and A8, 2006. Notes: For illustrative purposes only.Capacity values exclude combined-heat-and-power (CHP) data, but include end-use sector (industrial and commercial) non-C

 202
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) 11,558,205 2,232,495 6,594,096 78,312,583 2

(B) Capacity Factor(%) 36.0% 90.0% 80.0% 44.2% 

(C) Annual Hours 8,760 8,760 8,760 8,760 

(D) Annual ElectricityGeneration (kWh) 36,449,954,187 17,600,991,128 46,211,427,727 303,176,455,525 552,5

(E) Competing HeatRate (Btu/kWh) 10,107 10,107 10,107 10,107 

(F) Total Output(Million Btu) 368,399,686 177,893,217 467,058,900 3,064,204,435 5,5(G) Coal Heat Rate (Btu per short ton) 20,411,000 20,411,000 20,411,000 20,411,000 20,4

(H) Coal (short tons) 18,049,076 8,715,556 22,882,705 150,125,150 2

Sources: Capacity: EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Table A16, 2Capacity factors: Hydropower calculated from EIA, Annual Energy Outlook 2005, DOE/EIA-0383 (2005) (Washington, D.C., Feothers based on DOE, Renewable Energy Technology Characterizations, EPRI TR-109496, 1997 and Program data.Conversion Efficiency: EIA, Annual Energy Review 2004, DOE/EIA-0384(2003) (Washington, D.C., August 2005), Table A6. Heat Rate: Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Table H1. Notes: For illustrative purposes only, displacement of fossil generation depends on power system generation portfolio and dispatch ordCapacity values exclude combined-heat-and-power (CHP) data, but include end-use sector (industrial and commercial) non-CH

 203
Table 12.4 – National SO2 and Heat Input Data

1980 1985 1990 1995 20

SO2 (lbs) 34,523,334,000 32,184,330,000 31,466,566,000 23,671,357,600 22,404,150,5

SO2 Heat Factor (lb/MMBtu) 1.935 1.748 1.599 1.081 0.8

NOx (lbs) - - - 11,682,226,600 12,024,262,8

NOx Heat Factor (lb/MMBtu) - - - 0.534 0.4

Heat (MMBtu) 17,838,745,941 18,414,433,865 19,684,094,492 21,889,662,875 25,606,076,726 

Source: EPA, Clean Air Markets Web site - Data and Maps, Emissions section, http://cfpub.epa.gov/gdm/ accessed February 

 204
Table 12.5 – SO2, NOx, CO2 Emission Factors for Coal-Fired 

and Noncoal-Fired Title IV Affected Units 

1996 1997 1998 1999 2000 2001 2002 2

SO2 (lbs/mmBtu) 

 Coal 1.241 1.245 1.222 1.166 1.036 1.008 0.976 0

 Noncoal 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 0.794

NOx (lbs/mmBtu) 

 Coal 0.568 0.559 0.532 0.487 0.444 0.425 0.408 0

 Noncoal 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 0.348

CO2 (lbs/mmBtu) 

 Coal 206.377 205.537 205.677 205.586 205.646 205.627 205.672 201

 Noncoal 132.731 130.804 131.685 132.001 133.110 130.159 126.858

 Total 195.682 194.056 192.256 191.956 191.672 189.809 188.813

Source: EPA, Acid Rain Program Compliance Report 2001, Emission Scorecard, updated April 2004, Table 1, 

http://www.epa.gov/airmarkets/emissions/score01/index.html, and EPA, Clean Air Markets Web site - Data and Maps, Emissiosection, http://cfpub.epa.gov/gdm/ accessed March 2006.

 205
Boiler Type/Firing Configuration 

Fuel Emissions Units1 Cyclone

Fluidized 

Bed 

Opposed 

Firing 

Spreader 

Stoker Tangentia

Agricultural Byproducts Lbs per ton 0.08 0.01 0.08 0.08 0.0

Blast Furnace Gas Lbs per MMCF 3.5 0.35 3.5 3.5 3

Bituminous Coal* Lbs per ton 38 3.1 38 38 3

Black L Lbs per to

Distillate Fuel Oil* Lbs per MG 142 14.2 142 142 14

Jet Fuel* Lbs per MG 142 14.2 142 142 14Kerosene* Lbs per MG 142 14.2 142 142 14

Landfill Gas Lbs per MMCF 3.5 0.35 3.5 3.5 3Lignite Coal* Lbs per ton 30 1 30 30 3

Municipal Solid Waste Lbs per ton 1.7 0.17 1.7 1.7 1Natural Gas Lbs per MMCF 0.6 0.06 0.6 0.6 0

 Other Biomass Gas Lbs per MMCF 3.5 0.35 3.5 3.5 3Other Biomass Liquids Lbs per MG 1.42 1.42 1.42 1.42 1.4

Other Biomass Solids Lbs per ton 0.08 0.01 0.08 0.08 0.0

Other Gases Lbs per MMCF 3.5 0.35 3.5 3.5 3Other Lbs per MMCF 0.6 0.06 0.6 0.6 0

Petroleum Coke* Lbs per ton 39 3.9 39 39 3

Propane Gas Lbs per MMCF 0.6 0.06 0.6 0.6 0Residual Fuel Oil* Lbs per MG 157 15.7 157 157 15

Synthetic Coal* Lbs per ton 38 3.1 38 38 3Sludge Waste Lbs per ton 2.8 0.28 2.8 2.8 2

Subbituminous Coal* Lbs per ton *** 35 3.1 35 38 3Tire Derived Fuel* Lbs per ton 38 3.8 38 38 3

Waste Coal* Lbs per ton 38 3.1 38 38 3Wood Waste Liquids Lbs per MG 1.42 1.42 1.42 1.42 1.4

Wood Waste Solids Lbs per ton 0.08 0.01 0.08 0.08 0.0

Waste Oil* Lbs per MG 147 14.7 147 147 14

Table 12.6a – Sulfur Dioxide Uncontrolled Emission Factors, Electricity Generators 

iquor n *** 7 0.777

 206
Source: EIA, Electric Power Annual 2004, DOE/EIA-0348(2004) November 2005, Table A1. 

Notes:1 Lbs = pounds, MMCF = million cubic feet, MG = thousand gallons. 

* For these fuels, emissions are estimated by multiplying the emissions factor by the physical volume of fuel and the sulfur perc

(other fuels do not require the sulfur percentage in the calculation). Note that EIA data do not provide a sulfur content for TDF. (1.56 percent) is from http://www.epa.gov/appcdwww/aptb/EPA-600-R-01-109A.pdf, Table A-11. ** Source is EPA emission factors reported in http://www.epa.gov/ttn/chief/ap42/ and http://www.epa.gov/ttn/chief/software/fire

*** Although SLW and BLQ consist substantially of liquids, these fuels are measured and reported to EIA in tons. 

 207
Boiler Type/Firing Configuration1

Fuel Emissions Units2 Cyclone

Fluidized 

Bed 

Opposed 

Firing 

Spreader 

Stoker Tangential 

Agricultural Byproducts Lbs per ton 1.20 1.20 1.20 1.20 1.20 Blast Furnace Gas Lbs per MMCF 15.40 15.40 15.40 15.40 15.40 

Bituminous Coal Lbs per ton 33.00 5.00 22.00 11.00 15.0 [14.0] Black Liquor Lbs per ton *** 1.50 1.50 1.50 1.50 1.50 Distillate Fuel Oil Lbs per MG 24.00 24.00 24.00 24.00 24.00 

Jet Fuel Lbs per MG 24.00 24.00 24.00 24.00 24.00 

Kerosene Lbs per MG 24.00 24.00 24.00 24.00 24.00 

Landfill Gas Lbs per MMCF 72.40 72.40 72.40 72.40 72.40 

Lignite Coal Lbs per ton 15.00 3.60 13.00 5.80 7.10 Municipal Solid Waste Lbs per ton 5.90 5.90 5.90 5.90 5.90 

Natural Gas Lbs per MMCF 280.00 280.00 280.00 280.00 170.00 

Other Biomass Gas Lbs per MMCF 72.40 72.40 72.40 72.40 72.40 

Other Biomass Liquids Lbs per MG 1.66 1.66 1.66 1.66 1.66 

Other Biomass Solids Lbs per ton 1.20 1.20 1.20 1.20 1.20 

Other Gases Lbs per MMCF 14.90 14.90 14.90 14.90 14.90 

Other Lbs per MMCF 1.50 1.50 1.50 1.50 1.50 

Petroleum Coke Lbs per ton 21.00 21.00 21.00 21.00 21.00 

Propane Gas Lbs per MMCF 19.00 19.00 19.00 19.00 19.00 Residual Fuel Oil Lbs per MG 47.00 47.00 47.00 47.00 32.00 Synthetic Coal Lbs per ton 33.00 5.00 22.00 11.00 15.00 

Sludge Waste Lbs per ton 5.00 5.00 5.00 5.00 5.00 Subbituminous Coal Lbs per ton *** 17.00 5.00 12.00 8.80 8.40 

Table 12.6b – Nitrogen Oxide Uncontrolled Emissions Factors, Electricity Generator

 208
Tire Derived Fuel Lbs per ton 33.00 5.00 22.00 11.00 15.00 

Waste Coal Lbs per ton 21.70 21.70 21.70 21.70 21.70 

Wood Waste Liquids Lbs per MG 1.66 1.66 1.66 1.66 1.66 

Wood Waste Solids Lbs per ton 1.50 1.50 1.50 1.50 1.50 

Waste Oil Lbs per MG 19.00 19.00 19.00 19.00 19.00 

*** Although Sludge Waste and Black Liquor consist substantially of liquids, these fuels are measured and reported to EIA in toSource: EIA, Electric Power Annual 2004, DOE/EIA-0348(2004) November 2005, Table A1. Notes:

1 All Dry-Bottom Boilers, Except Wet-Bottom as indicated by values in brackets2 Lbs = pounds, MMCF = million cubic feet, MG = thousand gallons. 

** Source is EPA emission factors reported in http://www.epa.gov/ttn/chief/ap42/ and http://www.epa.gov/ttn/chief/software/fire

 209
Fuel 

Factor

(lbs of CO2 per MMBtu)*

Blast Furnace Gas 116.97Bituminous Coal 205.45Distillate Fuel Oil 161.27Geothermal 0.34Jet Fuel 159.41Kerosene 159.41Landfill Gas 115.12Lignite Coal 215.53Municipal Solid Waste 14.63Natural Gas 116.97Other Biomass Gas 115.11Other Gases 141.54Petroleum Coke 225.13Propane Gas 139.04Residual Fuel Oil 173.72Synthetic Coal 205.45Subbituminous Coal 212.58Waste Coal 205.16Waste Oil 163.61

Table 12.6c – Uncontrolled Carbon Dioxide Emissions Factors,Electricity Generators Source: EIA, Electric Power Annual 2004, DOE/EIA-0348(2004), November 2005, Table A1.* CO2 factors do not vary by boiler type or firing configuration. 

 210
Table 12.7 – Global Warming Potentials (GWP)

(100-year time horizon)Gas GWP 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 9,200C4F10 7,000C6F14 7,400SF6 23,

Source: EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003, EPA 430-R-05-003 (Final Version: Ap

Notes:The GWP of a greenhouse gas is the ratio of global warming, or radiative forcing – both direct and indirect – from one unit 

gas to that of one unit mass of carbon dioxide over a period of time. GWP from Intergovernmental Panel and Climate Change (IPCC) Second Assessment Report (SAR) and Third AssessmenAlthough the GWPs have been updated by the IPCC, estimates of emissions presented in this report use the GWPs from tReport. The UNFCCC reporting guidelines for national inventories were updated in 2002, but continue to require the use of 

that current estimates of aggregated greenhouse gas emissions for 1990 through 2001 are consistent with estimates develpublication of the TAR. Therefore, to comply with international reporting standards under the UNFCCC, official emission esthe United States using SAR GWP values. 

1 The methane GWP includes direct effects and those indirect effects, due to the production of tropospheric ozone and stra

The indirect effect due to the production of CO2 is not included. 

SAR

900

 211
Fossil Fuels 1

Residual Oil (million Btu per barrel) 6.287Distillate Oil (million Btu per barrel) 5.799Natural Gas (Btu per million cubic ft) 1,027Coal (million Btu per Short Ton) 20.411Biomass 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 6,000-8,000Sources:Table 12.8 – Approximate Heat Content of Selected Fuels for Electric-Power Generation1. EIA, Annual Energy Outlook 2006, DOE/EIA-0383 (2006) (Washington, D.C., February 2006), Table G1. 2. Animal Waste Screening Study, Electrotek Concepts Inc., Arlington, VA. June 2001. 

 212
1980 1990 2000 2001 2002 2003 2

Fossil-Fueled Steam-Electric Plants1, 2 10,388 10,402 10,201 10,146 10,119 10,107 10

Nuclear Steam-Electric Plants3 10,908 10,582 10,429 10,448 10,439 10,439 10Geothermal Energy Plants4 21,639 21,096 21,017 21,017 21,017 21,017 21

3 Used as the thermal-conversion factor for nuclear electricity net generation. 

Table 12.9 – Approximate Heat Rates for Electricity

(Btu per Kilowatthour)Source: EIA, Annual Energy Review 2004, DOE/EIA-0384 (2004) (Washington, D.C., August 2005), Table A6Notes:1 Through 2000, used as the thermal conversion factor for wood and waste electricity net generation at electric utilities. Fo

the thermal conversion factor for hydro, solar, and wind electricity net generation. 2 Through 2000, heat rates are for fossil-fueled steam-electric plants at electric utilities. Beginning in 2001, heat rates are 

plants at electric utilities and independent power producers.

4 Used as the thermal-conversion factor for geothermal electricity net generation. 

 213
1980 1990 2000 2001 2002 2003 2004 Normal1

January 887 728 886 935 778 944 957 917

February 831 655 643 725 670 801 769 732

March 680 535 494 669 624 572 487 593

April 338 321 341 302 282 344 302 345

May 142 184 115 115 185 165 105 159

June 49 29 29 29 23 41 28 39

July 5 6 12 8 3 4 5 9

August 10 10 12 6 8 5 16 15

September 54 56 69 71 38 62 42 77

October 316 246 244 267 299 261 241 282

November 564 457 610 400 561 477 484 539

December 831 789 1,005 696 813 784 788 817

Total 4,707 4,016 4,460 4,223 4,284 4,460 4,224 4,524

Table 12.10 – Heating Degree-Days by Month

Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 1.7 

Notes:

1 Based on calculations of data from 1971-2000

• This table excludes Alaska and Hawaii. • Degree-days are relative measurements of outdoor air temperature. Heating degree-days ar

deviations below the mean daily temperature of 65° F. For example, a weather station recording a mean daily temperature of 40° F woureport 25 heating degree-days. • Temperature information recorded by weather stations is used to calculate statewide degree-day averbased on resident state population. Beginning in 2002, data are weighted by the estimated 2000 population. The population-weighted sfigures are aggregated into Census divisions and the national average. Web Pages: • For data not shown for 1951-1969, see http://www.eia.doe.gov/emeu/aer/overview.html.• For current data, see http://www.eia.doe.gov/emeu/mer/overview.html. Sources: • 1942003 and Normals—U.S. Department of Commerce, National Oceanic and Atmospheric Administration (NOAA), National Climatic DataCenter, Asheville, North Carolina, Historical Climatology Series 5-1. • 2004—Energy Information Administration, Monthly Energy Review

February 2004-January 2005 issues, Table 1.10, which reports data from NOAA, National Weather Service Climate Prediction Center, Springs, Maryland. 

 214
1980 1990 2000 2001 2002 2003 2004 Normal1

January 9 15 10 9

Febru 8March 13 21 25 11 17 24 26 18

April 23 29 28 37 53 30 41 30

May 95 86 131 114 92 110 140 97

June 199 234 221 220 242 187 208 213

July 374 316 284 302 369 336 310 321

August 347 291 302 333 331 345 254 290

September 192 172 156 138 202 156 178 155

October 42 57 50 46 57 65 69 53

November 10 16 8 18 11 21 17 15

Decemb 8Total 1,313 1,260 1,229 1,245 1,393 1,281 1,260 1,215

Source: EIA, Annual Energy Review 2004, DOE/EIA-0384(2004) (Washington, D.C., August 2005), Table 1.8 

Table 12.11 – Cooling Degree-Days by Month

Notes:1 Based on calculations of data from 1971-2000

• This table excludes Alaska and Hawaii. • Degree-days are relative measurements of outdoor air temperature. Cooling degree-days ar

above the mean daily temperature of 65° F. For example, a weather station recording a mean daily temperature of 78° F would report 1

degree-days. • Temperature information recorded by weather stations is used to calculate statewide degree-day averages based on re

population. Beginning in 2002, data are weighted by the estimated 2000 population. The population-weighted state figures are aggregadivisions and the national average. Web Pages: • For data not shown for 1951-1969, see http://www.eia.doe.gov/emeu/aer/overview.htdata, see http://www.eia.doe.gov/emeu/mer/overview.html. Sources: • 1949-2003 and Normals—U.S. Department of Commerce, NatioAtmospheric Administration (NOAA), National Climatic Data Center, Asheville, North Carolina, Historical Climatology Series 5-2. • 2004Information Administration, Monthly Energy Review, February 2004-January 2005 issues, Table 1.11, which reports data from NOAA, NWeather Service Climate Prediction Center, Camp Springs, Maryland. 

3855

ary 4 14 10 12 6 7 5

er 5 9 4 11 5 4 6

 215
13.1 – Geographic Information System (GIS) Maps 

A Geographical Information System (GIS) is a computer-based system used to 

manipulate, manage, and analyze multidisciplinary geographic and related attribute data. 

The GIS system is composed of hardware, software, data, and expertise. A GIS system 

allows the user to perform several tasks, including data capture, data management, data 

manipulation, data analysis, and presentation of results in graphic or report forms. 

All information in GIS is linked to a spatial reference used to store and access data. GIS 

data layers can be recombined or manipulated, and analyzed with other layers of 

information. The GIS allows identification of relationships between features, within a 

common layer or across layers – and data can be queried or manipulated based on the 

tabular and/or the spatial characteristics. 

One set of maps (Figures 13.1, 13.3, 13.5, and 13.7) illustrates the natural renewable 

resource for the United States by quality of the resource. The transmission grid and the 

major load centers are overlaid on the resource maps. The major load centers represent 

the areas in the United States where the vast majority of electricity demand exists (large 

metropolitan areas). The maps featured here are simplified to make them easier to read. 

Higher-resolution resource maps are available online (see Online Resources later in this 

chapter. 

One of the challenges facing renewable energy is that, in many cases, areas with excellent 

renewable energy resources have little demand for electricity – while many major load 

centers are far from areas with good renewable resources. 

The other set of maps (Figures 13.2, 13.4, 13.6, and 13.8) shows the installed generating 

capacity from 1996 through 2005 by state. A number in the state shows generating 

capacity in MW, and a bar chart in the state shows the generating capacity over time. 

Biomass 

Biomass power utilizes biomass such as wood, agricultural waste, and yard waste through 

combustion. The biomass fuel is either directly combusted in a boiler, or gasified and 

then combusted, or turned into a liquid fuel that can be combusted (see the Biomass 

section of Chapter 2 for more detail on biomass technologies). 

Natural Resource 

The majority of biomass resources exist east of the Continental Divide (Figure 13.1). 

Biomass resources are derived from the vegetation. Because the western part of the 

United States has sparse vegetation, the biomass resource in the Western states is 

generally poor. The Eastern states have much higher-quality resources; and many major 

load centers in Eastern states are near areas with excellent biomass resources. Alaska has 

limited biomass resources, while Hawaii has excellent biomass resources on some of the 

islands. 
Installed Capacity 

Biomass-generating capacity was nearly level during the past decade, with a slight 

decline in the past few years (Figure 13.2). The largest states, in terms of generating 

capacity, are Florida (1,051 MW), California (799 MW), and Maine (788 MW). 

Geothermal 

Geothermal technologies for power generation utilize heat from underground sources to 

generate electricity. Plants are currently operating in the Western United States (see the 

Geothermal section of Chapter 2 for more details on geothermal technologies). 

Natural Resource 

The majority of high-quality geothermal resources exist in the western part of the United 

States – and, in particular, the Southwest (Figure 13.3). Most of the major load areas in 

the Eastern states are not near any high-quality geothermal resources. The Western states 

are more promising, as several of the major load centers are in – or close to – high-quality 

geothermal resources. A good supply of high-quality geothermal resources exists in 

sparsely populated areas in the West. Alaska and Hawaii both have some areas with 

excellent geothermal resources. 

Installed Capacity 

Geothermal generation is currently located in three Western states (Figure 13.4). 

California is by far the largest (2,802 MW), followed by Nevada (272 MW) and Utah 

(38MW). 

Solar 

The two most commonly deployed solar power technologies are photovoltaic (PV) and 

concentrating solar thermal power (CSP) (see the Solar section of Chapter 2 for more 

information on solar technologies). 

Natural Resource 

The southern parts of the United States, and especially the southwest, have the greatest 

potential for solar energy (Figure 13.5). This is determined largely by latitude and 

weather patterns. Solar resources generally decline in quality, moving east and north from 

the Southwest. The Northeast, as a whole, generally has moderate-quality solar resources. 

Alaska has moderate solar resources, while Hawaii has good – to very good – solar 

resources. 

Installed Capacity 

This map features concentrating solar thermal power (CSP) generating capacity (Figure 

13.6). Total CSP-generating capacity is virtually unchanged over the past decade. 

California has the most CSP generating capacity, by far (418 MW), followed by Arizona 

(10 MW), New York (0.5 MW), Nevada (0.3 MW), and Pennsylvania (0.3 MW). 
Wind 

Wind power utilizes naturally occurring wind patterns to drive turbines that generate 

electricity (see the Wind section of Chapter 2 for more information on wind power 

technologies). 

Natural Resource 

The wind resources of the United States fall into two major categories: 1) onshore, and 2) 

offshore. So far, most of the wind resource assessments focused on onshore wind. Most 

of the best onshore wind resource is in the Midwestern states (Figure 13.7). Many of the 

major load centers in the Eastern states are not located near good wind resources, while 

some Western load centers are located close to high-quality wind resources. 

Installed Capacity 

Wind power is the most consistently growing renewable energy technology among those 

featured in this chapter (Figure 13.8). California is the largest state, in terms of capacity 

(2,150 MW), with Texas close behind (1,995 MW). Iowa, the third-largest state (836 

MW), has less than half the capacity of the largest states. Wind-generating capacity is 

growing rapidly in many states. 

Online Resources 

For more GIS information, including dynamic maps, GIS data, and analysis tools – as 

well as downloadable high-resolution maps – please see the NREL GIS Web site at 

http://www.nrel.gov/gis 
Figure 13.1. Biomass Resources, Transmission, and Load Centers 
Figure 13.2. Installed Biomass Generating Capacity 
Figure 13.3. Geothermal Resources, Transmission, and Load Centers 
Figure 13.4. Installed Geothermal Generating Capacity 
Figure 13.5. Direct Normal Solar Resources, Transmission, and Load Centers 
Figure 13.6. Installed CSP Generating Capacity 
Figure 13.7. Wind Resources, Transmission, and Load Centers 
Figure 13.8. Installed Wind Generating Capacity 
REPORT DOCUMENTATION PAGE Form Approved 

OMB No. 0704-0188 

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources,

gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this 

collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents 

should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a

currently valid OMB control number. 

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION. 

1. REPORT DATE (DD-MM-YYYY) 

August 2006 

2. REPORT TYPE 

Technical Report 

3. DATES COVERED (From - To) 

4. TITLE AND SUBTITLE 

Power Technologies Energy Data Book—Fourth Edition 

5a. CONTRACT NUMBER 

DE-AC36-99-GO10337 

5b. GRANT NUMBER 

5c. PROGRAM ELEMENT NUMBER 

6. AUTHOR(S) 

Compiled by Jørn Aabakken 

5d. PROJECT NUMBER 

NREL/TP-620-39728 

5e. TASK NUMBER 

WUA3.1000 

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-620-39728 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSOR/MONITOR'S ACRONYM(S) 

NREL 

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 Strategic Energy Analysis Center, 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: 17. LIMITATION 

OF ABSTRACT 

UL 

18. NUMBER 

OF PAGES 

19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified 

c. THIS PAGE 

Unclassified 19b. TELEPHONE NUMBER (Include area code) 

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18 

F1147-E(12/2004)